Reorganization of Title 30: Bureaus of Safety and Environmental Enforcement and Ocean Energy Management, 64432-64780 [2011-22675]
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Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations
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
Bureau of Safety and
Environmental Enforcement (BSEE);
Interior, Bureau of Ocean Energy
Management (BOEM); Interior.
ACTION: Direct final rule.
AGENCY:
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, email address: kumkum.ray@boemre.gov.
SUPPLEMENTARY INFORMATION:
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SUMMARY:
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
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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
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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 nongovernmental 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
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Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations
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:
Æ Change § 250.101(a) to 550.101(a)),
Æ Change § 250.123 to 30 CFR
250.123,
Æ Change ‘‘see § 250.111’’ to ‘‘see
§ 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
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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 crossreferences to earlier approvals or other
actions taken under redesignated
sections. This rule replaces the crossreferences 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
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Part 203—Relief or Reduction in
Royalty Rates.
Retained in its entirety in BSEE,
chapter II.
Part 219—Distribution and Disbursement of Royalties, Rentals,
and Bonuses.
Moved in its entirety to BOEM,
chapter V, part 519.
BSEE will oversee the administration of 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.
BOEM will perform revenue share calculations for 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 Sulphur
Operations in the Outer Continental Shelf.
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Responsibilities divided between
BOEM and BSEE.
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Both bureaus have responsibilities that are related to operations on
OCS leases. These responsibilities were divided between the two
bureaus as detailed in Table B.
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TABLE A—DERIVATION TABLE—Continued
Title 30—Mineral Resources
Chapter II—Bureau of Ocean Energy Management, Regulation and Enforcement
Current part
New location
Justification
Part 251—Geological and Geophysical (G&G) Explorations of
the Outer Continental Shelf.
Responsibilities divided between
BOEM and BSEE.
Part 252—Outer Continental Shelf
(OCS) Oil and Gas Information
Program.
Both BOEM and BSEE will have
this part in its entirety.
Part 253—Oil Spill Financial Responsibility for Offshore Facilities.
Moved to BOEM in its entirety,
chapter V, part 553.
Part 254—Oil-Spill Response Requirements for Facilities Located
Seaward of the Coast Line.
Part 256—Leasing of Sulphur or Oil
and Gas in the Outer Continental
Shelf.
Retained in its entirety in BSEE ....
Part 259—Mineral Leasing: Definitions.
Part 260—Outer Continental Shelf
Oil and Gas Leasing.
Part 270—Nondiscrimination in the
Outer Continental Shelf.
Moved to BOEM in its entirety,
chapter V, part 559.
Moved to BOEM in its entirety,
chapter V, part 560.
Both BOEM and BSEE will have
this part in its entirety.
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.
Part 281—Leasing of Minerals
Other Than Oil, Gas, and Sulphur in the Outer Continental
Shelf.
Part 282—Operations in the Outer
Continental Shelf for Minerals
Other Than Oil, Gas, and Sulphur.
Part 285—Renewable Energy and
Alternate Uses of Existing Facilities on the Outer Continental
Shelf.
Moved to BOEM in its entirety,
chapter V, part 581.
BOEM will be responsible for issuing the permits 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 regulates how and when the date and information 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.
BOEM is responsible for all activities related to financial 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.
All oil-spill related activities, except for financial responsibility, will fall
under BSEE, under its responsibility for oil-spill response. Further
details are provided in Table F.
BOEM has primary responsibility for 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.
BOEM is responsible for leasing activities. Further details are provided in Table H.
BOEM is responsible for leasing activities. Further details are provided in Table I.
Both BOEM and BSEE are responsible for ensuring that 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.
This part regulates 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. 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.
This part regulates leasing for minerals other than oil, gas, and sulphur in the OCS. Leasing activities are a BOEM responsibility. Further details are provided in Table L.
Responsibilities divided between
BOEM and BSEE.
Responsibilities divided between
BOEM and BSEE.
Moved in its entirety to BOEM,
chapter V, part 585.
Both BOEM and BSEE have responsibilities for 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.
At this time, the renewable energy program will be 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
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Part 290—Appeal Procedures ........
Part 291—Open and Nondiscriminatory Access to Oil and Gas
Pipelines under the Outer Continental Shelf Lands Act.
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Both BOEM and BSEE will have
this part in its entirety.
Retained in its entirety in BSEE ....
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Appeal procedures apply to decisions and orders issued by both
BOEM and BSEE. Further details are provided in Table O.
This part deals with access to pipelines. All aspects of pipelines, including operations are under the responsibility of BSEE. Further
details are provided in Table P.
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The reorganization of the individual
parts and subparts is as follows:
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Subchapter B—Offshore
Subchapter A—Minerals Revenue
Management
Part 219—Distribution and
Disbursement of Royalties, Rentals, and
Bonuses—Moved in Its Entirety to
BOEM, Chapter V, Part 519
Part 203—Relief or Reduction in Royalty
Rates—Retained in Its Entirety in BSEE,
Chapter II
BOEM will perform revenue share
calculations for OCS receipts shared
under GOMESA.
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.
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 250—Oil and Gas and Sulphur
Operations in the Outer Continental
Shelf
TABLE B—DETAILED TABLE FOR PART 250
Current citation and BSEE citation
(if applicable)
Implementing bureau and BOEM
citation (if applicable)
Explanation
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.
§ 250.101
bility.
Authority and applica-
Both BSEE and BOEM, § 550.101
§ 250.102
What does this part do?
Both BSEE and BOEM, § 550.102
§ 250.103 Where can I find more
information about the requirements in this part?
Both BSEE and BOEM, § 550.103
§ 250.104 How may I appeal a
decision made under MMS regulations?
§ 250.105 Definitions ....................
Both BSEE and BOEM, § 550.104
Both BSEE and BOEM, § 550.105
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§ 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?
Retained by BSEE .........................
§ 250.115 How do I determine
well producibility?
§ 250.116 How do I determine
producibility if my well is in the
Gulf of Mexico?
§ 250.117 How does a determination of well producibility affect
royalty status?
§ 250.118 Will MMS approve gas
injection?
Moved to BOEM, §§ 550.115,
550.116, and 550.117.
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Retained by BSEE .........................
Retained by BSEE .........................
Retained by BSEE .........................
Retained by BSEE .........................
Retained by BSEE .........................
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Establishes authority for the entire part, 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.
This section describes the 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.
This section establishes the authority for the 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.
This section explains how a lessee or operator may appeal a decision made by either BSEE or BOEM, it is informational and important to include in both sets of regulations.
This section contains the definitions used in parts 250 and 550, the
same definitions will apply to both sets of regulations.
This section defines the standards for performance that BSEE will
use to regulate lease operations, these operations fall under the
authority of BSEE.
This section establishes the expectations for operators to protect
health, safety, and the environment, these responsibilities fall under
the authority of BSEE.
Addresses cranes and other material-handling equipment, which is
related to an offshore operation that is under the authority of
BSEE.
These sections address welding requirements, which are related to
offshore operations that are under the authority of BSEE.
Addresses the installation and operation of electrical equipment,
which are related to offshore operations that are under the authority of BSEE.
Addresses well producibility that is under the authority of BOEM.
Addresses gas injection operations that are under the authority of
BSEE.
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TABLE B—DETAILED TABLE FOR PART 250—Continued
Current citation and BSEE citation
(if applicable)
Implementing bureau and BOEM
citation (if applicable)
Explanation
§ 250.119 Will MMS approve subsurface gas storage?
§ 250.120 How does injecting,
storing, or treating gas affect my
royalty payments?
§ 250.121 What happens when
the reservoir contains both original gas in place and injected
gas?
§ 250.122 What effect does subsurface storage have on the
lease term?
§ 250.123 Will MMS allow gas
storage on unleased lands?
Moved to BOEM, § 550.119 ..........
Retained by BSE ...........................
Addresses subsurface gas storage that is under the authority of
BOEM.
These pertain to gas storage operations that are under the authority
of BSEE.
Both BSEE and BOEM § 550.122
This section clarifies that an approved storage project has no effect
on lease term.
Moved to BOEM, § 550.123 ..........
§ 250.124
injection
taining a
§ 250.125
Retained by BSEE .........................
This section allows gas storage on unleased lands, through a rightof-use and easement (RUE). RUEs are issued by BOEM, under
their responsibility for resource management.
This section addresses gas injection operations.
Offshore operations are under the authority of BSEE.
Will MMS approve gas
into the cap rock consulphur deposit?
Service fees .................
Both BSEE and BOEM, § 550.125
Both BSEE and BOEM, § 550.126
§ 250.141 May I ever use alternate procedures or equipment?
Both BSEE and BOEM, § 550.141
§ 250.142 How do I receive approval for departures?
Both BSEE and BOEM, § 550.142
§ 250.143 How do I designate an
operator?
§ 250.144 How do I designate a
new operator when a designation
of operator terminates?
§ 250.145 How do I designate an
agent or a local agent?
§ 250.146 Who is responsible for
fulfilling leasehold obligations?
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§ 250.126 Electronic payment instructions.
§ 250.130 Why does MMS conduct inspections?
§ 250.131 Will MMS notify me before conducting an inspection?
§ 250.132 What must I do when
MMS conducts an inspection?
§ 250.133 Will MMS reimburse me
for my expenses related to inspections?
§ 250.135 What will MMS do if my
operating performance is unacceptable?
§ 250.136 How will MMS determine if my operating performance
is unacceptable?
§ 250.140 When will I receive an
oral approval?
Moved to BOEM, § 550.143 ..........
§ 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?
Retained by BSEE .........................
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Retained by BSEE .........................
Retained by BSEE .........................
Both BSEE and BOEM will oversee activities that require collection of
a service fee.
Provides information on how to pay the fees collected by BSEE and
BOEM.
BSEE will be responsible for issuing permits and notices and inspecting the operations under approved leases, plans, and permit.
BSEE will be responsible for inspecting operations and activities on
the OCS.
Both
BSEE
and
BOEM,
§§ 550.135 and 550.136.
BSEE is responsible for finding operator performance unacceptable
under the criteria of § 550.136, but the final adjudication is a BOEM
action.
Both BSEE and BOEM, § 550.140,
except for paragraph (c), which
will remain with BSEE only.
Both BSEE and BOEM may grant verbal approvals for activities and
operations under their respective authorities. Paragraph (c) addresses oral approvals for gas flaring that will be regulated only by
BSEE.
This section explains how a lessee or 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.
This section provides information on how a 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.
This section addresses the designation of an operator that is under
the authority of BOEM.
This section addresses the designation of an operator that is under
the authority of BOEM.
Moved to BOEM, § 550.144 ..........
Both BSEE and BOEM, § 550.145
Both BSEE and BOEM, § 550.146
Retained by BSEE .........................
Retained by BSEE .........................
Retained by BSEE .........................
Retained by BSEE .........................
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This section addresses the designation of an agent that is under the
authority of both BSEE and BOEM.
This section provides information on who is responsible for fulfilling
leasehold obligations. These activities are conducted under the authority of both BSEE and BOEM.
This section provides information on naming facilities and wells in the
Gulf of Mexico region that is under the authority of BSEE.
This section provides information on naming facilities and wells in the
Pacific region that are under the authority of BSEE.
This section provides information on naming facilities and wells in the
Alaska region that are under the authority of BSEE.
This section provides information on renaming existing facilities and
wells that are under the authority of BSEE.
This section provides information on the required identification signs
that must be displayed that are under the authority of BSEE.
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TABLE B—DETAILED TABLE FOR PART 250—Continued
Implementing bureau and BOEM
citation (if applicable)
Explanation
§ 250.160 When will MMS grant
me a right-of-use and easement,
and what requirements must I
meet?
§ 250.161 What else must I submit with my application?
Moved to BOEM, § 550.160 ..........
This section provides information on the requirements that must be
met to obtain a RUE. RUEs are issued by BOEM under their responsibility for resource management.
Moved to BOEM, § 550.161 ..........
§ 250.162 May I continue my
right-of-use and easement after
the termination of any lease on
which it is situated?
§ 250.163 If I have a State lease,
will MMS grant me a right-of-use
and easement?
§ 250.164 If I have a State lease,
what conditions apply for a rightof-use and easement?
§ 250.165 If I have a State lease,
what fees do I have to pay for a
right-of-use and easement?
§ 250.166 If I have a State lease,
what surety bond must I have for
a right-of-use and easement?
§ 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?
§ 250.180 What am I required to
do to keep my lease term in effect?
§ 250.181 When may the Secretary cancel my lease and when
am I compensated for cancellation?
Moved to BOEM, § 550.162 ..........
This section provides information on additional requirements that
must be contained in the RUE application. RUEs are issued by
BOEM under their responsibility for resource management.
This section provides information on RUEs that are issued by BOEM
under their responsibility for resource management.
§ 250.182 When may the Secretary cancel a lease at the exploration stage?
mstockstill on DSK4VPTVN1PROD with RULES2
Current citation and BSEE citation
(if applicable)
Moved to BOEM, § 550.182 ..........
§ 250.183 When may MMS or the
Secretary extend or cancel a
lease at the development and
production stage?
Moved to BOEM, § 550.183 ..........
§ 250.184 What is the amount of
compensation for lease cancellation?
§ 250.185 When is there no compensation for a lease cancellation?
Moved to BOEM, § 550.184 ..........
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Moved to BOEM, § 550.163 ..........
This section concerns RUEs that are issued by BOEM under their responsibility for resource management.
Moved to BOEM, § 550.164 ..........
This section provides information on RUEs that are issued by BOEM
under their responsibility for resource management.
Moved to BOEM, § 550.165 ..........
This section provides information on RUEs that are issued by BOEM
under their responsibility for resource management.
Moved to BOEM, § 550.166 ..........
This section provides information on RUEs that are issued by BOEM
under their responsibility for resource management.
Retained by BSEE .........................
These sections address suspension of operations or production. Offshore operations are under the authority of BSEE.
Retained by BSEE .........................
These sections address suspension of operations or production. Offshore operations are under the authority of BSEE.
Retained by BSEE.
Retained by BSEE.
Retained by BSEE .........................
Retained by BSEE .........................
This section addresses suspension of operations. Offshore operations are under the authority of BSEE.
These sections address suspension of operations or production. Offshore operations are under the authority of BSEE.
Retained by BSEE .........................
This section addresses requirements for keeping a lease term in effect. BSEE will determine if a lease meets these requirements.
Moved to BOEM, § 550.181 ..........
This section addresses lease cancellations. 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.
This section addresses lease 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.
This section addresses lease cancellations. 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.
This section addresses lease cancellations. Offshore lease administration, including lease terms, is under the authority of BOEM.
Moved to BOEM, § 550.185 ..........
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TABLE B—DETAILED TABLE FOR PART 250—Continued
Current citation and BSEE citation
(if applicable)
Implementing bureau and BOEM
citation (if applicable)
Explanation
§ 250.186 What reporting information and report forms must I submit?
§ 250.187 What are MMS’ incident
reporting requirements?
§ 250.188 What incidents must I
report to MMS and when must I
report them?
§ 250.189 Reporting requirements
for incidents requiring immediate
notification.
§ 250.190 Reporting requirements
for incidents requiring written notification.
§ 250.191 How does MMS conduct incident investigations?
§ 250.192 What reports and statistics must I submit relating to a
hurricane, earthquake, or other
natural occurrence?
§ 250.193 Reports and investigations of apparent violations.
§ 250.194 How must I protect archaeological resources?
Both BSEE and BOEM, § 550.186
This section provides information concerning reporting requirements
and form submission This information is applicable to both BSEE
and BOEM activities.
This section addresses incident reporting requirements for offshore
operations that are under the authority of BSEE.
This section addresses incident reporting requirements for offshore
operations that are under the authority of BSEE.
§ 250.195 What notification does
MMS require on the production
status of wells?
§ 250.196 Reimbursements for reproduction and processing costs.
§ 250.197 Data and information to
be made available to the public
or for limited inspection.
§ 250.198 Documents
porated by reference.
incor-
§ 250.199 Paperwork
Reduction
Act statements—information collection.
Retained by BSEE .........................
Retained by BSEE .........................
Retained by BSEE .........................
This section addresses incident reporting requirements for offshore
operations that are under the authority of BSEE.
Retained by BSEE .........................
This section addresses incident reporting requirements for offshore
operations that are under the authority of BSEE.
Retained by BSEE .........................
This section addresses incident investigations for offshore operations
that are under the authority of BSEE.
This section requires operators to submit information relating to the
impact of hurricanes on on-going offshore operations, which are
under the authority of BSEE.
Retained by BSEE .........................
Retained by BSEE .........................
Moved to BOEM, paragraph (c) retained by BSEE and also in
BOEM with cross reference.
Retained by BSEE .........................
Both BSEE and BOEM, § 550.196
BOEM—Introductory
paragraph
and paragraphs (a)(6), (9), (10),
(b), (c)(4), (5), and (6).
BSEE—Introductory
paragraph
and paragraphs (a)(1) through
(5), (7), (8), (b), (c)(1) through
(5) and (7) retained in BSEE.
Retained by BSEE .........................
Both BSEE and BOEM, § 550.199
This section addresses incident reporting requirements for offshore
operations that are under the authority of BSEE.
BOEM is responsible for plans. Paragraph (c) directs operators to report to BSEE any archaeological resource discovered while conducting operations in a lease or right-of-way area.
This section addresses the production status of 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.
Data and information may be requested by either BSEE or BOEM.
Both BSEE and BOEM will collect and be responsible for various
types of information. This section describes 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.
This section addresses documents incorporated by reference and
pertains to both BSEE and BOEM activities—e.g. Renewable Energy in BOEM.
This section addresses the Paperwork Reduction Act that is applicable to both BSEE and BOEM.
mstockstill on DSK4VPTVN1PROD with RULES2
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).
§ 250.200 Definitions ....................
§ 250.201 What plans and information must I submit before I
conduct any activities on my
lease or unit?
§ 250.202 What criteria must the
Exploration Plan (EP), Development and Production Plan (DPP),
or Development Operations Coordination Document (DOCD)
meet?
§ 250.203 Where can wells be located under an EP, DPP, or
DOCD?
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Both BSEE and BOEM, § 550.200
Both BSEE and BOEM, § 550.201
Definitions section, the same definitions apply to both bureaus.
This section addresses plans that are the responsibility of BOEM.
BSEE is responsible for DWOPs.
Moved to BOEM, § 550.202 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.203 ..........
This section addresses plans that are the responsibility of BOEM.
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TABLE B—DETAILED TABLE FOR PART 250—Continued
Implementing bureau and BOEM
citation (if applicable)
Explanation
§ 250.204 How must I protect the
rights of the Federal Government?
mstockstill on DSK4VPTVN1PROD with RULES2
Current citation and BSEE citation
(if applicable)
Retained by BSEE .........................
§ 250.205 Are there special requirements if my well affects an
adjacent property?
§ 250.206 How do I submit the
EP, DPP, or DOCD?
§ 250.207 What ancillary activities
may I conduct?
§ 250.208 If I conduct ancillary activities, what notices must I provide?
§ 250.209 What is the MMS review process for the notice?
§ 250.210 If I conduct ancillary activities, what reporting and data/
information retention requirements must I satisfy?
§ 250.211 What must the EP include?
§ 250.212 What information must
accompany the EP?
§ 250.213 What general information must accompany the EP?
§ 250.214 What geological and
geophysical (G&G) information
must accompany the EP?
§ 250.215 What hydrogen sulfide
(H2S) information must accompany the EP?
§ 250.216 What biological, physical, and socioeconomic information must accompany the EP?
§ 250.217 What solid and liquid
wastes and discharges information and cooling water intake information must accompany the
EP?
§ 250.218 What air emissions information must accompany the
EP?
§ 250.219 What oil and hazardous
substance spills information must
accompany the EP?
§ 250.220 If I propose activities in
the Alaska OCS Region, what
planning information must accompany the EP?
§ 250.221 What
environmental
monitoring information must accompany the EP?
§ 250.222 What lease stipulations
information must accompany the
EP?
§ 250.223 What mitigation measures information must accompany the EP?
§ 250.224 What information on
support vessels, offshore vehicles, and aircraft you will use
must accompany the EP?
§ 250.225 What information on the
onshore support facilities you will
use must accompany the EP?
§ 250.226 What Coastal Zone
Management Act (CZMA) information must accompany the EP?
Retained by BSEE .........................
Moved to BOEM, § 550.206 ..........
This section describes the 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.
This section describes the measures operators must take to protect
the rights of adjacent lessees during offshore operations. Offshore
operations are under the authority of BSEE.
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.207 ..........
This section is under the responsibility of BOEM.
Moved to BOEM, § 550.208 ..........
This section is under the responsibility of BOEM.
Moved to BOEM, § 550.209 ..........
This section is under the responsibility of BOEM.
Moved to BOEM, § 550.210 ..........
This section is under the responsibility of BOEM.
Moved to BOEM, § 550.211 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.212 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.213 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.214 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.215 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.216 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.217 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.218 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.219 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.220 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.221 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.222 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.223 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.224 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.225 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.226 ..........
This section addresses plans that are the responsibility of BOEM.
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TABLE B—DETAILED TABLE FOR PART 250—Continued
mstockstill on DSK4VPTVN1PROD with RULES2
Current citation and BSEE citation
(if applicable)
Implementing bureau and BOEM
citation (if applicable)
§ 250.227 What environmental impact analysis (EIA) information
must accompany the EP?
§ 250.228 What administrative information must accompany the
EP?
§ 250.231 After receiving the EP,
what will MMS do?
§ 250.232 What actions will MMS
take after the EP is deemed submitted?
§ 250.233 What decisions will
MMS make on the EP and within
what timeframe?
§ 250.234 How do I submit a
modified EP or resubmit a disapproved EP, and when will
MMS make a decision?
§ 250.235 If a State objects to the
EP’s coastal zone consistency
certification, what can I do?
§ 250.241 What must the DPP or
DOCD include?
§ 250.242 What information must
accompany the DPP or DOCD?
§ 250.243 What general information must accompany the DPP or
DOCD?
§ 250.244 What geological and
geophysical (G&G) information
must accompany the DPP or
DOCD?
§ 250.245 What hydrogen sulfide
(H2S) information must accompany the DPP or DOCD?
§ 250.246 What mineral resource
conservation information must
accompany the DPP or DOCD?
§ 250.247 What biological, physical, and socioeconomic information must accompany the DPP or
DOCD?
§ 250.248 What solid and liquid
wastes and discharges information and cooling water intake information must accompany the
DPP or DOCD?
§ 250.249 What air emissions information must accompany the
DPP or DOCD?
§ 250.250 What oil and hazardous
substance spills information must
accompany the DPP or DOCD?
§ 250.251 If I propose activities in
the Alaska OCS Region, what
planning information must accompany the DPP?
§ 250.252 What
environmental
monitoring information must accompany the DPP or DOCD?
§ 250.253 What lease stipulations
information must accompany the
DPP or DOCD?
§ 250.254 What mitigation measures information must accompany the DPP or DOCD?
§ 250.255 What decommissioning
information must accompany the
DPP or DOCD?
Moved to BOEM, § 550.227 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.228 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.231 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.232 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.233 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.234 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.235 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.241 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.242 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.243 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.244 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.245 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.246 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.247 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.248 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.249 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.250 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.251 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.252 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.253 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.254 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.255 ..........
This section addresses plans that are the responsibility of BOEM.
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TABLE B—DETAILED TABLE FOR PART 250—Continued
mstockstill on DSK4VPTVN1PROD with RULES2
Current citation and BSEE citation
(if applicable)
Implementing bureau and BOEM
citation (if applicable)
§ 250.256 What related facilities
and operations information must
accompany the DPP or DOCD?
§ 250.257 What information on the
support vessels, offshore vehicles, and aircraft you will use
must accompany the DPP or
DOCD?
§ 250.258 What information on the
onshore support facilities you will
use must accompany the DPP or
DOCD?
§ 250.259 What sulphur operations information must accompany the DPP or DOCD?
§ 250.260 What Coastal Zone
Management Act (CZMA) information must accompany the DPP
or DOCD?
§ 250.261 What environmental impact analysis (EIA) information
must accompany the DPP or
DOCD?
§ 250.262 What administrative information must accompany the
DPP or DOCD?
§ 250.266 After receiving the DPP
or DOCD, what will MMS do?
§ 250.267 What actions will MMS
take after the DPP or DOCD is
deemed submitted?
§ 250.268 How does MMS respond to recommendations?
§ 250.269 How will MMS evaluate
the environmental impacts of the
DPP or DOCD?
§ 250.270 What decisions will
MMS make on the DPP or
DOCD and within what timeframe?
§ 250.271 For what reasons will
MMS disapprove the DPP or
DOCD?
§ 250.272 If a State objects to the
DPP’s or DOCD’s coastal zone
consistency certification, what
can I do?
§ 250.273 How do I submit a
modified DPP or DOCD or resubmit a disapproved DPP or
DOCD?
§ 250.280 How must I conduct activities under the approved EP,
DPP, or DOCD?
§ 250.281 What must I do to conduct activities under the approved EP, DPP, or DOCD?
§ 250.282 Do I have to conduct
post-approval monitoring?
§ 250.283 When must I revise or
supplement the approved EP,
DPP, or DOCD?
§ 250.284 How will MMS require
revisions to the approved EP,
DPP, or DOCD?
§ 250.285 How do I submit revised and supplemental EPs,
DPPs, and DOCDs?
§ 250.286 What is a DWOP?
Moved to BOEM, § 550.256 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.257 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.258 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.259 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.260 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.261 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.262 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.266 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.267 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.268 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.269 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.270 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.271 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.272 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.273 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.280 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.281 ..........
This section addresses plans that are the responsibility of BOEM.
Both BSEE and BOEM, § 550.282
Moved to BOEM, § 550.283 ..........
Both BOEM and BSEE will have oversight functions for post-approval
monitoring.
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.284 ..........
This section addresses plans that are the responsibility of BOEM.
Moved to BOEM, § 550.285 ..........
This section addresses plans that are the responsibility of BOEM.
Retained by BSEE .........................
This section addresses DWOPs that are part of Field Operations and
under the authority of BSEE.
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TABLE B—DETAILED TABLE FOR PART 250—Continued
Current citation and BSEE citation
(if applicable)
Implementing bureau and BOEM
citation (if applicable)
Explanation
§ 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?
§ 250.296 When and how must I
submit a CID or a revision to a
CID?
Retained by BSEE .........................
§ 250.297 What information must
a CID contain?
Moved to BOEM, § 550.297 ..........
§ 250.298 How long will MMS
take to evaluate and make a decision on the CID?
§ 250.299 What operations require
approval of the CID?
Moved to BOEM, § 550.298 ..........
This section addresses DWOPs that are part of Field Operations and
under the authority of BSEE.
This section addresses DWOPs that are part of Field Operations and
under the authority of BSEE.
This section addresses DWOPs that are part of Field Operations and
under the authority of BSEE.
This section addresses DWOPs that are part of Field Operations and
under the authority of BSEE.
This section addresses DWOPs that are part of Field Operations and
under the authority of BSEE.
This section addresses DWOPs that are part of Field Operations and
under the authority of BSEE.
This section addresses DWOPs that are part of Field Operations and
under the authority of BSEE.
This section addresses DWOPs that are part of Field Operations and
under the authority of BSEE.
This section addresses DWOPs that are part of Field Operations and
under the authority of BSEE.
This section addresses 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.
This section 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.
This section 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.
This section 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.
Retained by BSEE .........................
Retained by BSEE .........................
Retained by BSEE .........................
Retained by BSEE .........................
Retained by BSEE .........................
Retained by BSEE .........................
Retained by BSEE .........................
Retained by BSEE .........................
Moved to BOEM, § 550.296 ..........
Moved to BOEM, § 550.299 ..........
Subpart C—Pollution Prevention and Control
§ 250.300
Pollution prevention .....
Retained by BSEE .........................
§ 250.301 Inspection of facilities ...
§ 250.302 Definitions concerning
air quality.
§ 250.303 Facilities described in a
new or revised Exploration Plan
or Development and Production
Plan.
§ 250.304 Existing facilities ...........
Retained by BSEE .........................
Moved to BOEM, § 550.302 ..........
Moved to BOEM, § 550.303 ..........
Moved to BOEM, § 550.304 ..........
This section addresses pollution prevention during offshore operations. Offshore operations are under the authority of BSEE.
BSEE will be responsible for all inspection activities on the OCS.
This section pertains to air quality concerns that are under the authority of BOEM.
This section pertains to air quality concerns that are under the authority of BOEM.
This section pertains 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.
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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.
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TABLE B—DETAILED TABLE FOR PART 250—Continued
Current citation and BSEE citation
(if applicable)
Implementing bureau and BOEM
citation (if applicable)
Explanation
Subpart J—Pipelines and Pipeline Rights-of-Way
Mostly retained by BSEE, except for provisions related to bond requirements (§ 250.1011). Bonding for all activities is the responsibility of
BOEM, and the bonding section will be moved to § 550.1011. The rest of pipeline operations, including the issuance of pipeline rights-of-way,
are under the authority of BSEE.
§ 250.1000
General requirements.
Retained by BSEE .........................
§ 250.1001
Definitions ..................
Retained by BSEE .........................
requirements
Retained by BSEE .........................
§ 250.1003 Installation,
testing,
and repair requirements for DOI
pipelines.
§ 250.1004 Safety equipment requirements for DOI pipelines.
Retained by BSEE .........................
§ 250.1005 Inspection
requirements for DOI pipelines.
Retained by BSEE .........................
§ 250.1006 How must I decommission and take out of service a
DOI pipeline?
§ 250.1007 What to include in applications.
Retained by BSEE .........................
§ 250.1008
Reports .......................
Retained by BSEE .........................
§ 250.1009 Requirements to obtain pipeline right-of-way grants.
Retained by BSEE .........................
§ 250.1010 General requirements
for pipeline right-of-way holders.
Retained by BSEE .........................
§ 250.1011 Bond requirements for
pipeline right-of-way holders.
§ 250.1012 Required payments for
pipeline right-of-way holders.
Moved to BOEM, § 550.1011 ........
§ 250.1013 Grounds for forfeiture
of pipeline right-of-way grants.
Retained by BSEE .........................
§ 250.1014 When pipeline right-ofway grants expire.
Retained by BSEE .........................
§ 250.1015 Applications for pipeline right-of-way grants.
Retained by BSEE .........................
§ 250.1016 Granting
rights-of-way.
pipeline
Retained by BSEE .........................
§ 250.1017 Requirements for construction under pipeline right-ofway grants.
§ 250.1018 Assignment of pipeline
right-of-way grants.
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§ 250.1002 Design
for DOI pipelines.
Retained by BSEE .........................
§ 250.1019 Relinquishment
pipeline right-of-way grants.
Retained by BSEE .........................
of
Retained by BSEE .........................
Retained by BSEE .........................
Retained by BSEE .........................
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.
This section addresses pipelines and pipeline rights-of-way on the
OCS, which are offshore operations. Offshore operations are under
the authority of 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.
This section addresses pipelines and pipeline rights-of-way on the
OCS, which are offshore operations. Offshore operations are under
the authority of 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.
This section addresses pipelines and pipeline rights-of-way on the
OCS, which are offshore operations. Offshore operations are under
the authority of 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.
This section addresses pipelines and pipeline rights-of-way on the
OCS, which are offshore operations. Offshore operations are under
the authority of 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.
This section addresses pipelines 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.
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.
All bonding is under the authority of BOEM.
The pipeline rights-of-way
pipeline operations that
BSEE.
The pipeline rights-of-way
pipeline operations that
BSEE.
The pipeline rights-of-way
pipeline operations that
BSEE.
The pipeline rights-of-way
pipeline operations that
BSEE.
The pipeline rights-of-way
pipeline operations that
BSEE.
The pipeline rights-of-way
pipeline operations that
BSEE.
The pipeline rights-of-way
pipeline operations that
BSEE.
The pipeline rights-of-way
pipeline operations that
BSEE.
are so closely related to the regulation of
it is most efficient to vest the authority in
are so closely related to the regulation of
it is most efficient to vest the authority in
are so closely related to the regulation of
it is most efficient to vest the authority in
are so closely related to the regulation of
it is most efficient to vest the authority in
are so closely related to the regulation of
it is most efficient to vest the authority in
are so closely related to the regulation of
it is most efficient to vest the authority in
are so closely related to the regulation of
it is most efficient to vest the authority in
are so closely related to the regulation of
it is most efficient to vest the authority in
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.
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TABLE B—DETAILED TABLE FOR PART 250—Continued
Current citation and BSEE citation
(if applicable)
Implementing bureau and BOEM
citation (if applicable)
Explanation
§ 250.1150 What are the general
reservoir
production
requirements?
§ 250.1151 How often must I conduct well production tests?
§ 250.1152 How do I conduct well
tests?
§ 250.1153 When must I conduct
a static bottomhole pressure survey?
§ 250.1154 How do I determine if
my reservoir is sensitive?
Retained by BSEE .........................
This section addresses oil and gas production requirements that are
part of offshore operations and are under the authority of BSEE.
Retained by BSEE .........................
§ 250.1155 What information must
I submit for sensitive reservoirs?
Moved to BOEM, § 550.1155 ........
§ 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?
§ 250.1159 May the Regional Supervisor limit my well or reservoir
production rates?
§ 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?
§ 250.1165 What must I do for enhanced recovery operations?
Retained by BSEE .........................
This section addresses oil and gas production requirements that are
part of offshore operations and are under the authority of BSEE.
This section addresses oil and gas production requirements that are
part of offshore operations and are under the authority of BSEE.
BOEM will oversee these requirements because they are operator reporting requirements that can be separated from BSEE’s enforcement responsibilities.
BOEM will oversee these requirements because they are operator reporting requirements that can be separated from BSEE’s enforcement responsibilities.
BOEM will oversee these requirements because they are operator reporting requirements that can be separated from BSEE’s enforcement responsibilities.
This section addresses oil and gas production requirements that are
part of offshore operations and are under the authority of BSEE.
§ 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?
Retained by BSEE .........................
Moved to BOEM, § 550.1153 ........
Moved to BOEM, § 550.1154 ........
Retained by BSEE .........................
This section addresses oil and gas production requirements that are
part of offshore operations and are under the authority of BSEE.
Retained by BSEE .........................
This section addresses oil and gas production requirements that are
part of offshore operations and are under the authority of BSEE.
Retained by BSEE .........................
This section addresses oil and gas production requirements that are
part of offshore operations and are under the authority of BSEE.
Retained by BSEE .........................
This section addresses oil and gas production requirements that are
part of offshore operations and are under the authority of BSEE.
This section addresses oil and gas production requirements that are
part of offshore operations and are under the authority of BSEE.
Retained by BSEE .........................
Retained by BSEE .........................
Retained by BSEE .........................
This section addresses oil and gas production requirements that are
part of offshore operations and are under the authority of BSEE.
This section addresses oil and gas production requirements that are
part of offshore operations and are under the authority of BSEE.
Retained by BSEE .........................
This section addresses oil and gas production requirements that are
part of offshore operations and are under the authority of BSEE.
Responsibilities divided between This section addresses oil and gas production requirements that are
BSEE and BOEM, § 550.1165(b).
part of offshore operations and are under the authority of BSEE.
Paragraph 550.1165 (b) refers operators to BSEE for approval.
Responsibilities divided between BSEE will oversee these requirements because they are operator reBSEE and BOEM, § 550.1166(c).
porting requirements. Paragraph 550.1166(c) requires the lessee/
operator to request the Maximum Efficient Rate (MER) when submitting Form BOEM–0127 as required under § 550.1155 for sensitive reservoirs.
Responsibilities divided between This section addresses information to be submitted; both BSEE and
BSEE and BOEM.
BOEM functions.
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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.
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TABLE B—DETAILED TABLE FOR PART 250—Continued
Current citation and BSEE citation
(if applicable)
Implementing bureau and BOEM
citation (if applicable)
Explanation
Subpart N—Outer Continental Shelf (OCS) Civil Penalties
Retained in both bureaus in its entirety, with the exception of provisions in current § 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
Current citation and BSEE citation
(if applicable)
Implementing bureau and BOEM
citation (if applicable)
Explanation
PART 251—GEOLOGICAL AND GEOPHYSICAL (G&G) EXPLORATIONS OF THE OUTER CONTINENTAL SHELF
Definitions ........................
Purpose of this part .........
Both BSEE and BOEM, § 551.1 ....
Moved to BOEM, § 551.2 ..............
§ 251.3 Authority and applicability
of this part.
§ 251.4 Types of G&G activities
that require permits or Notices.
§ 251.5 Applying for permits or filing Notices.
§ 251.6 Obligations and rights
under a permit or a Notice.
§ 251.7 Test
drilling
activities
under a permit.
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§ 251.1
§ 251.2
Both BSEE and BOEM, § 551.3 ....
§ 251.8 Inspection and reporting
requirements for activities under
a permit.
§ 251.9 Temporarily
stopping,
canceling, or relinquishing activities approved under a permit.
§ 251.10 Penalties and appeals ...
Moved to BOEM, § 551.8 ..............
§ 251.11 Submission, inspection,
and selection of geological data
and information collected under a
permit and processed by permittees or third parties.
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Moved to BOEM, § 551.4 ..............
Moved to BOEM, § 551.5 ..............
Moved to BOEM, § 551.6 ..............
Responsibilities divided between
both BSEE and BOEM.
Definitions section, the same definitions apply to both bureaus.
This section addresses prelease G&G activities. Prelease activities
are under the authority of BOEM.
This section addresses prelease G&G activities. Prelease activities
are under the authority of BOEM.
This section addresses prelease G&G activities. Prelease activities
are under the authority of BOEM.
This section addresses prelease G&G activities. Prelease activities
are under the authority of BOEM.
This section addresses prelease G&G activities. Prelease activities
are under the authority of BOEM.
All of paragraph (b) regulates drilling activities, which are operations
that require a permit, under the authority of BSEE. All of § 551.7,
except (b)(6) and (b)(8), is under BOEM.
This section addresses prelease G&G activities. Prelease activities
are under the authority of BOEM.
Moved to BOEM, § 551.9 ..............
This section addresses prelease G&G activities. Prelease activities
are under the authority of BOEM.
Moved to BOEM, § 551.10 ............
This section addresses prelease G&G activities. Prelease activities
are under the authority of BOEM.
This section addresses prelease G&G activities. Prelease activities
are under the authority of BOEM.
Moved to BOEM, § 551.11 ............
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TABLE C—DETAILED TABLE FOR PART 251—Continued
Current citation and BSEE citation
(if applicable)
Implementing bureau and BOEM
citation (if applicable)
Explanation
§ 251.12 Submission, inspection,
and selection of geophysical data
and information collected under a
permit and processed by permittees or third parties.
§ 251.13 Reimbursement for the
costs of reproducing data and information and certain processing
costs.
§ 251.14 Protecting and disclosing
data and information submitted to
MMS under a permit.
§ 251.15 Authority for information
collection.
Moved to BOEM, § 551.12 ............
This section addresses prelease G&G activities. Prelease activities
are under the authority of BOEM.
Moved to BOEM, § 551.13 ............
This section addresses prelease G&G activities. Prelease activities
are under the authority of BOEM.
Moved to BOEM, § 551.14 ............
This section addresses prelease G&G activities. Prelease activities
are under the authority of BOEM.
In both BSEE and BOEM § 551.15
This section establishes the 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
Current citation and BSEE citation
(if applicable)
Implementing bureau and BOEM
citation (if applicable)
Explanation
PART 252—OUTER CONTINENTAL SHELF (OCS) OIL AND GAS INFORMATION PROGRAM
§ 252.1
Purpose ............................
In both BSEE and BOEM § 552.1
§ 252.2
Definitions ........................
In both BSEE and BOEM § 552.2
§ 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.
In both BSEE and BOEM § 552.3
Both BSEE and BOEM will collect, 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.
Definitions section. The same definitions apply to both sets of regulations.
Both BSEE and BOEM will collect.
In both BSEE and BOEM § 552.4
Both BSEE and BOEM will collect.
In both BSEE and BOEM § 552.5
Both BSEE and BOEM will collect.
In both BSEE and BOEM § 552.6
Both BSEE and BOEM will collect.
In both BSEE and BOEM § 552.7
Both BSEE and BOEM will collect.
Part 253—Oil Spill Financial
Responsibility for Offshore Facilities—
Moved to BOEM in Its Entirety, Chapter
V Part 523
under its mission to manage the
development of offshore resources in an
economically responsible way.
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All financial responsibility functions
will be under the authority of BOEM,
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TABLE E—DETAILED TABLE FOR PART 253
Current citation and BSEE citation
(if applicable)
Implementing bureau and BOEM
citation (if applicable)
Explanation
Subpart A—General
§ 253.1 What is the purpose of
this part?
Moved to BOEM, § 553.1 ..............
§ 253.3 How are the terms used
in this regulation defined?
§ 253.5 What is the authority for
collecting Oil Spill Financial Responsibility (OSFR) information?
Moved to BOEM, § 553.3 ..............
BOEM is responsible 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.
BOEM is responsible for all activities related to financial assurance.
Moved to BOEM, § 553.5 ..............
BOEM is responsible for all activities related to financial assurance.
Subpart B—Applicability and Amount of OSFR
§ 253.10 What facilities does this
part cover?
§ 253.11 Who must demonstrate
OSFR?
§ 253.12 May I ask MMS for a determination of whether I must
demonstrate OSFR?
§ 253.13 How much OSFR must I
demonstrate?
§ 253.14 How do I determine the
worst case oil-spill discharge volume?
§ 253.15 What are my general
OSFR compliance responsibilities?
Moved to BOEM, § 553.10 ............
BOEM is responsible for all activities related to financial assurance.
Moved to BOEM, § 553.11 ............
BOEM is responsible for all activities related to financial assurance.
Moved to BOEM, § 553.12 ............
BOEM is responsible for all activities related to financial assurance.
Moved to BOEM, § 553.13 ............
BOEM is responsible for all activities related to financial assurance.
Moved to BOEM, § 553.14 ............
BOEM is responsible for all activities related to financial assurance.
Moved to BOEM, § 553.15 ............
BOEM is responsible for all activities related to financial assurance.
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Subpart C—Methods for Demonstrating OSFR
§ 253.20 What methods may I use
to demonstrate OSFR?
§ 253.21 How can I use self-insurance as OSFR evidence?
§ 253.22 How do I apply to use
self-insurance as OSFR evidence?
§ 253.23 What information must I
submit to support my net worth
demonstration?
§ 253.24 When I submit audited
annual financial statements to
verify my net worth, what standards must they meet?
§ 253.25 What financial test procedures must I use to determine
the amount of self-insurance allowed as OSFR evidence based
on net worth?
§ 253.26 What information must I
submit
to
support
my
unencumbered
assets
demonstration?
§ 253.27 When I submit audited
annual financial statements to
verify my unencumbered assets,
what standards must they meet?
§ 253.28 What financial test procedures must I use to evaluate
the amount of self-insurance allowed as OSFR evidence based
on unencumbered assets?
§ 253.29 How can I use insurance
as OSFR evidence?
§ 253.30 How can I use an indemnity as OSFR evidence?
§ 253.31 How can I use a surety
bond as OSFR evidence?
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Moved to BOEM, § 553.20 ............
BOEM is responsible for all activities related to financial assurance.
Moved to BOEM, § 553.21 ............
BOEM is responsible for all activities related to financial assurance.
Moved to BOEM, § 553.22 ............
BOEM is responsible for all activities related to financial assurance.
Moved to BOEM, § 553.23 ............
BOEM is responsible for all activities related to financial assurance.
Moved to BOEM, § 553.24 ............
BOEM is responsible for all activities related to financial assurance.
Moved to BOEM, § 553.25 ............
BOEM is responsible for all activities related to financial assurance.
Moved to BOEM, § 553.26 ............
BOEM is responsible for all activities related to financial assurance.
Moved to BOEM, § 553.27 ............
BOEM is responsible for all activities related to financial assurance.
Moved to BOEM, § 553.28 ............
BOEM is responsible for all activities related to financial assurance.
Moved to BOEM, § 553.29 ............
BOEM is responsible for all activities related to financial assurance.
Moved to BOEM, § 553.30 ............
BOEM is responsible for all activities related to financial assurance.
Moved to BOEM, § 553.31 ............
BOEM is responsible for all activities related to financial assurance.
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TABLE E—DETAILED TABLE FOR PART 253—Continued
Current citation and BSEE citation
(if applicable)
Implementing bureau and BOEM
citation (if applicable)
§ 253.32 Are there alternative
methods to demonstrate OSFR?
Moved to BOEM, § 553.32 ............
Explanation
BOEM is responsible for all activities related to financial assurance.
Subpart D—Requirements for Submitting OSFR Information
§ 253.40 What OSFR evidence
must I submit to MMS?
§ 253.41 What terms must I include in my OSFR evidence?
§ 253.42 How can I amend my list
of COFs?
§ 253.43 When is my OSFR demonstration or the amendment to
my OSFR demonstration effective?
§ 253.44 [Reserved] ......................
§ 253.45 Where do I send my
OSFR evidence?
Moved to BOEM, § 553.40 ............
BOEM is responsible for all activities related to financial assurance.
Moved to BOEM, § 553.41 ............
BOEM is responsible for all activities related to financial assurance.
Moved to BOEM, § 553.42 ............
BOEM is responsible for all activities related to financial assurance.
Moved to BOEM, § 553.43 ............
BOEM is responsible for all activities related to financial assurance.
§ 553.44 [Reserved] ....................
Moved to BOEM, § 553.45 ............
BOEM is responsible for all activities related to financial assurance.
BOEM is responsible for all activities related to financial assurance.
Subpart E—Revocation and Penalties
§ 253.50 How can MMS refuse or
invalidate my OSFR evidence?
§ 253.51 What are the penalties
for not complying with this part?
Moved to BOEM, § 553.50 ............
BOEM is responsible for all activities related to financial assurance.
Moved to BOEM, § 553.51 ............
BOEM is responsible for all activities related to financial assurance.
Subpart F—Claims for Oil-Spill Removal Costs and Damages
§ 253.60 To whom may I present
a claim?
§ 253.61 When is a guarantor
subject to direct action for
claims?
§ 253.62 What are the designated
applicant’s notification obligations
regarding a claim?
Appendix—Appendix to Part 253—
List of U.S. Geological Survey
Topographic Maps.
Moved to BOEM, § 553.60 ............
BOEM is responsible for all activities related to financial assurance.
Moved to BOEM, § 553.61 ............
BOEM is responsible for all activities related to financial assurance.
Moved to BOEM, § 553.62 ............
BOEM is responsible for all activities related to financial assurance.
Moved to BOEM, Appendix to part
553.
BOEM is responsible for all activities related to financial assurance.
Part 254—Oil-Spill Response
Requirements for Facilities Located
Seaward of the Coast Line—Retained in
Its Entirety in BSEE
responsibility for enforcement of
environmental compliance
requirements.
All oil-spill response functions will
be managed by BSEE under its
TABLE F—DETAILED TABLE FOR PART 254
Current citation and BSEE citation
(if applicable)
Implementing bureau and BOEM
citation (if applicable)
Explanation
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Subpart A—General
§ 254.1 Who must submit a spillresponse 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 MMS?
VerDate Mar<15>2010
16:55 Oct 17, 2011
Retained in
chapter II.
Retained in
chapter II.
Retained in
chapter II.
Retained in
chapter II.
Retained in
chapter II.
Retained in
chapter II.
Retained in
chapter II.
Jkt 226001
its entirety in BSEE,
its entirety in BSEE,
its entirety in BSEE,
its entirety in BSEE,
its entirety in BSEE,
its entirety in BSEE,
its entirety in BSEE,
PO 00000
Frm 00018
Fmt 4701
All oil spill related regulations, except for financial responsibility,
under BSEE, under its responsibility for oil spill response.
All oil spill related regulations, except for financial responsibility,
under BSEE, under its responsibility for oil spill response.
All oil spill related regulations, except for financial responsibility,
under BSEE, under its responsibility for oil spill response.
All oil spill related regulations, except for financial responsibility,
under BSEE, under its responsibility for oil spill response.
All oil spill related regulations, except for financial responsibility,
under BSEE, under its responsibility for oil spill response.
All oil spill related regulations, except for financial responsibility,
under BSEE, under its responsibility for oil spill response.
All oil spill related regulations, except for financial responsibility,
under BSEE, under its responsibility for oil spill response.
Sfmt 4700
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are
are
are
are
are
are
are
Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations
64449
TABLE F—DETAILED TABLE FOR PART 254—Continued
Current citation and BSEE citation
(if applicable)
Implementing bureau and BOEM
citation (if applicable)
Explanation
§ 254.8 May I appeal decisions
under this part?
§ 254.9 Authority for information
collection.
Retained in its entirety in BSEE,
chapter II.
Retained in its entirety in BSEE,
chapter II.
All oil spill related regulations, except for financial responsibility, are
under BSEE, under its responsibility for oil spill response.
All oil spill related regulations, except for financial responsibility, are
under BSEE, under its responsibility for oil spill response.
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?
§ 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?
Retained in its entirety in BSEE,
chapter II.
Retained in its entirety in BSEE,
chapter II.
Retained in its entirety in BSEE,
chapter II.
All oil spill related regulations, except for financial responsibility, are
under BSEE, under its responsibility for oil spill response.
All oil spill related regulations, except for financial responsibility, are
under BSEE, under its responsibility for oil spill response.
All oil spill related regulations, except for financial responsibility, are
under BSEE, under its responsibility for oil spill response.
Retained in its entirety in BSEE,
chapter II.
All oil spill related regulations, except for financial responsibility, are
under BSEE, under its responsibility for oil spill response.
Retained in its entirety in BSEE,
chapter II.
All oil spill related regulations, except for financial responsibility, are
under BSEE, under its responsibility for oil spill response.
Retained in its entirety in BSEE,
chapter II.
All oil spill related regulations, except for financial responsibility, are
under BSEE, under its responsibility for oil spill response.
Retained in its entirety in BSEE,
chapter II.
All oil spill related regulations, except for financial responsibility, are
under BSEE, under its responsibility for oil spill response.
Retained in its entirety in BSEE,
chapter II.
All oil spill related regulations, except for financial responsibility, are
under BSEE, under its responsibility for oil spill response.
Retained in its entirety in BSEE,
chapter II.
All oil spill related regulations, except for financial responsibility, are
under BSEE, under its responsibility for oil spill response.
Retained in its entirety in BSEE,
chapter II.
All oil spill related regulations, except for financial responsibility, are
under BSEE, under its responsibility for oil spill response.
Retained in its entirety in BSEE,
chapter II.
All oil spill related regulations, except for financial responsibility, are
under BSEE, under its responsibility for oil spill response.
Subpart C—Related Requirements for Outer Continental Shelf Facilities
Retained in
chapter II.
§ 254.41 Training your response Retained in
personnel.
chapter II.
§ 254.42 Exercises for your re- Retained in
sponse personnel and equipment.
chapter II.
§ 254.43 Maintenance and peri- Retained in
odic inspection of response
chapter II.
equipment.
§ 254.44 Calculating
response Retained in
equipment effective daily recovchapter II.
ery capacities.
§ 254.45 Verifying the capabilities Retained in
of your response equipment.
chapter II.
§ 254.46 Whom do I notify if an oil Retained in
spill occurs?
chapter II.
§ 254.47 Determining the volume Retained in
of oil of your worst case dischapter II.
charge scenario.
mstockstill on DSK4VPTVN1PROD with RULES2
§ 254.40
Records ..........................
its entirety in BSEE,
its entirety in BSEE,
its entirety in BSEE,
its entirety in BSEE,
All oil spill related regulations, except for financial responsibility,
under BSEE, under its responsibility for oil spill response.
All oil spill related regulations, except for financial responsibility,
under BSEE, under its responsibility for oil spill response.
All oil spill related regulations, except for financial responsibility,
under BSEE, under its responsibility for oil spill response.
All oil spill related regulations, except for financial responsibility,
under BSEE, under its responsibility for oil spill response.
are
are
are
are
its entirety in BSEE,
All oil spill related regulations, except for financial responsibility, are
under BSEE, under its responsibility for oil spill response.
its entirety in BSEE,
All oil spill related regulations, except for financial responsibility, are
under BSEE, under its responsibility for oil spill response.
All oil spill related regulations, except for financial responsibility, are
under BSEE, under its responsibility for oil spill response.
All oil spill related regulations, except for financial responsibility, are
under BSEE, under its responsibility for oil spill response.
its entirety in BSEE,
its entirety in BSEE,
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.
VerDate Mar<15>2010
16:55 Oct 17, 2011
Retained in its entirety in BSEE,
chapter II.
All oil spill related regulations, except for financial responsibility, are
under BSEE, under its responsibility for oil spill response.
Retained in its entirety in BSEE,
chapter II.
Retained in its entirety in BSEE,
chapter II.
All oil spill related regulations, except for financial responsibility, are
under BSEE, under its responsibility for oil spill response.
All oil spill related regulations, except for financial responsibility, are
under BSEE, under its responsibility for oil spill response.
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64450
Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations
TABLE F—DETAILED TABLE FOR PART 254—Continued
Current citation and BSEE citation
(if applicable)
Implementing bureau and BOEM
citation (if applicable)
Explanation
§ 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.
Retained in its entirety in BSEE,
chapter II.
All oil spill related regulations, except for financial responsibility, are
under BSEE, under its responsibility for oil spill response.
Retained in its entirety in BSEE,
chapter II.
All oil spill related regulations, except for financial 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
Current citation and BSEE citation
(if applicable)
Implementing bureau and BOEM
citation (if applicable)
Explanation
Subpart A—Outer Continental Shelf Oil, Gas, and Sulphur Management, General
§ 256.0 Authority for information
collection.
§ 256.1 Purpose ............................
Moved to BOEM, § 556.0 ..............
§ 256.2
Policy ................................
Moved to BOEM, § 556.1, retained
purpose except for right-of-way
grant clause; under BSEE retained right-of-way grant clause.
Moved to BOEM, § 556.2 ..............
§ 256.4
Authority ...........................
Moved to BOEM, § 556.4 ..............
§ 256.5
Definitions ........................
Moved to BOEM, § 556.5 ..............
§ 256.7
Cross references ..............
Both BSEE and BOEM § 556.7 .....
§ 256.8 Leasing maps and diagrams.
§ 256.10 Information to States ......
Moved to BOEM, § 556.8 ..............
§ 256.11
Helium ............................
Moved to BOEM, § 556.11 ............
§ 256.12
Supplemental sales ........
Moved to BOEM, § 556.12 ............
Moved to BOEM, § 556.10 ............
This section addresses leasing activities on the OCS that are under
the authority of BOEM.
This section addresses leasing activities on the OCS that are under
the authority of BOEM.
This section addresses leasing activities
the authority of BOEM.
This section addresses leasing activities
the authority of BOEM.
This section addresses leasing activities
the authority of BOEM.
This section contains cross references
BSEE and BOEM activities.
This section addresses leasing activities
the authority of BOEM.
This section addresses leasing activities
the authority of BOEM.
This section addresses leasing activities
the authority of BOEM.
This section addresses leasing activities
the authority of BOEM.
on the OCS that are under
on the OCS that are under
on the OCS that are under
that are pertinent to both
on the OCS that are under
on the OCS that are under
on the OCS that are under
on the OCS that are under
Subpart B—Oil and Gas Leasing Program
§ 256.16 Receipt and consideration of nominations; public notice and participation.
§ 256.17 Review by State and
local governments and other persons.
§ 256.19 Periodic
consultation
with interested parties.
§ 256.20 Consideration of coastal
zone management program.
Moved to BOEM, § 556.16 ............
This section addresses leasing activities on the OCS that are under
the authority of BOEM.
Moved to BOEM, § 556.17 ............
This section addresses leasing activities on the OCS that are under
the authority of BOEM.
Moved to BOEM, § 556.19 ............
This section addresses leasing activities on the OCS that are under
the authority of BOEM.
This section addresses leasing activities on the OCS that are under
the authority of BOEM.
Moved to BOEM, § 556.20 ............
Subpart C—Reports From Federal Agencies
mstockstill on DSK4VPTVN1PROD with RULES2
§ 256.22
General ..........................
Moved to BOEM, § 556.22 ............
This section addresses leasing activities on the OCS that are under
the authority of BOEM.
Subpart D—Call for Information and Nominations
§ 256.23
Information on areas ......
§ 256.25 Areas
states.
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coastal
16:55 Oct 17, 2011
Moved to BOEM, § 556.23 ............
Moved to BOEM, § 556.25 ............
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This section addresses leasing activities on the OCS that are under
the authority of BOEM.
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TABLE G—DETAILED TABLE FOR PART 256—Continued
Current citation and BSEE citation
(if applicable)
Implementing bureau and BOEM
citation (if applicable)
Explanation
Subpart E—Area Identification and Tract Size
§ 256.26
General ..........................
Moved to BOEM, § 556.26 ............
§ 256.28
Tract size .......................
Moved to BOEM, § 556.28 ............
This section addresses leasing activities on the OCS that are under
the authority of BOEM.
This section addresses leasing activities on the OCS that are under
the authority of BOEM.
Subpart F—Lease Sales
§ 256.29
Proposed notice of sale
Moved to BOEM, § 556.29 ............
§ 256.31
State comments .............
Moved to BOEM, § 556.31 ............
§ 256.32
Notice of sale .................
Moved to BOEM, § 556.32 ............
This section addresses leasing activities on the OCS that are under
the authority of BOEM.
This section addresses leasing activities on the OCS that are under
the authority of BOEM.
This section addresses leasing activities on the OCS that are under
the authority of BOEM.
Subpart G—Issuance of Leases
§ 256.35
Qualifications of lessees
Moved to BOEM, § 556.35 ............
§ 256.37
Lease term .....................
Moved to BOEM, § 556.37 ............
§ 256.38
Joint bidding provisions
Moved to BOEM, § 556.38 ............
§ 256.40
Definitions ......................
Moved to BOEM, § 556.40 ............
§ 256.41 Joint bidding requirements.
§ 256.43 Chargeability for production.
§ 256.44 Bids disqualified .............
Moved to BOEM, § 556.41 ............
Moved to BOEM, § 556.44 ............
§ 256.46
Submission of bids .........
Moved to BOEM, § 556.46 ............
§ 256.47
Award of leases .............
Moved to BOEM, § 556.47 ............
§ 256.49
Lease form .....................
Moved to BOEM, § 556.49 ............
§ 256.50
Dating of leases .............
Moved to BOEM, § 556.50 ............
Moved to BOEM, § 556.43 ............
This section addresses leasing
the authority of BOEM.
This section addresses leasing
the authority of BOEM.
This section addresses leasing
the authority of BOEM.
This section addresses leasing
the authority of BOEM.
This section addresses leasing
the authority of BOEM.
This section addresses leasing
the authority of BOEM.
This section addresses leasing
the authority of BOEM.
This section addresses leasing
the authority of BOEM.
This section addresses leasing
the authority of BOEM.
This section addresses leasing
the authority of BOEM.
This section addresses leasing
the authority of BOEM.
activities on the OCS that are under
activities on the OCS that are under
activities on the OCS that are under
activities on the OCS that are under
activities on the OCS that are under
activities on the OCS that are under
activities on the OCS that are under
activities on the OCS that are under
activities on the OCS that are under
activities on the OCS that are under
activities on the OCS that are under
Subpart H—Rentals and Royalties [Reserved]
Subpart I—Bonding
§ 256.52 Bond requirements for
an oil and gas or sulphur lease.
§ 256.53 Additional bonds ............
§ 256.54 General requirements for
bonds.
§ 256.55 Lapse of bond ................
mstockstill on DSK4VPTVN1PROD with RULES2
§ 256.56 Lease-specific abandonment accounts.
§ 256.57 Using a third-party guarantee instead of a bond.
§ 256.58 Termination of the period
of liability and cancellation of a
bond.
§ 256.59 Forfeiture of bonds and/
or other securities.
Moved to BOEM, § 556.52 ............
Moved to BOEM, § 556.53 ............
Moved to BOEM, § 556.54 ............
Moved to BOEM, § 556.55 ............
Moved to BOEM, § 556.56 ............
Moved to BOEM, § 556.57 ............
Moved to BOEM, § 556.58 ............
Moved to BOEM, § 556.59 ............
This section addresses leasing
the authority of BOEM.
This section addresses leasing
the authority of BOEM.
This section addresses leasing
the authority of BOEM.
This section addresses leasing
the authority of BOEM.
This section addresses leasing
the authority of BOEM.
This section addresses leasing
the authority of BOEM.
This section addresses leasing
the authority of BOEM.
activities on the OCS that are under
activities on the OCS that are under
activities on the OCS that are under
activities on the OCS that are under
activities on the OCS that are under
activities on the OCS that are under
activities on the OCS that are under
This section addresses leasing activities on the OCS that are under
the authority of BOEM.
Subpart J—Assignments, Transfers, and Extensions
§ 256.62 Assignment of lease or
interest in lease.
§ 256.63 Service fees ...................
Moved to BOEM, § 556.63 ............
§ 256.64
Moved to BOEM, § 556.64 ............
How to file transfers .......
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16:55 Oct 17, 2011
Moved to BOEM, § 556.62 ............
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This section addresses leasing activities on the OCS that are under
the authority of BOEM.
This section addresses leasing activities on the OCS that are under
the authority of BOEM.
This section addresses leasing activities on the OCS that are under
the authority of BOEM.
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Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations
TABLE G—DETAILED TABLE FOR PART 256—Continued
Current citation and BSEE citation
(if applicable)
§ 256.65
Implementing bureau and BOEM
citation (if applicable)
Moved to BOEM, § 556.65 ............
Attorney General review
§ 256.67 Separate filings for assignments.
§ 256.68 Effect of assignment of a
particular tract.
§ 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.
Explanation
Both BSEE and BOEM § 556.70 ...
This section addresses leasing activities on the OCS that are under
the authority of BOEM.
This section addresses leasing activities on the OCS that are under
the authority of BOEM.
This section addresses leasing activities on the OCS that are under
the authority of BOEM.
Needed by both agencies.
Both BSEE and BOEM § 556.71 ...
Both BSEE and BOEM § 556.72 ...
Needed by both agencies.
Needed by both agencies.
Retained by BSEE .........................
This section 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.
Moved to BOEM, § 556.67 ............
Moved to BOEM, § 556.68 ............
Subpart K—Termination of Leases
§ 256.76 Relinquishment of leases
or parts of leases.
§ 256.77 Cancellation of leases ....
Moved to BOEM, § 556.76 ............
Both BSEE and BOEM, § 556.77 ..
This section addresses leasing administration on the OCS that are
under the authority of BOEM.
BOEM is authorized to cancel leases. BSEE has the authority to initiate lease cancellation.
Subpart L—Section 6 Leases
§ 256.79
lease.
§ 256.80
Effect of regulations on
Both BSEE and BOEM § 556.79 ...
Needed by both agencies.
Leases of other minerals
Moved to BOEM, § 556.80 ............
This section addresses leasing administration on the OCS that are
under the authority of BOEM.
Subpart M—Studies
§ 256.82
Environmental studies ....
Moved to BOEM, § 556.82 ............
This section 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
mstockstill on DSK4VPTVN1PROD with RULES2
§ 256.90 Which leases may I exchange for a bonus or royalty
credit?
§ 256.91 How much bonus or royalty credit will MMS grant in exchange for a lease?
§ 256.92 What must I do to obtain
a bonus or royalty credit?
§ 256.93 How is the bonus or royalty credit allocated among multiple lease owners?
§ 256.94 How may I use the
bonus or royalty credit?
§ 256.95 How do I transfer a
bonus or royalty credit to another
person?
APPENDIX A PART 256—Appendix A to Part 256—Oil and Gas
Cash Bonus Bid.
Moved to BOEM, § 556.90 ............
This section addresses leasing activities on the OCS that are under
the authority of BOEM.
Moved to BOEM, § 556.91 ............
This section addresses leasing activities on the OCS that are under
the authority of BOEM.
Moved to BOEM, § 556.92 ............
This section addresses leasing activities on the OCS that are under
the authority of BOEM.
This section addresses leasing activities on the OCS that are under
the authority of BOEM.
Moved to BOEM, § 556.93 ............
Moved to BOEM, § 556.94 ............
Moved to BOEM, § 556.95 ............
This section addresses leasing activities on the OCS that are under
the authority of BOEM.
This section addresses leasing activities on the OCS that are under
the authority of BOEM.
Moved to BOEM, APPENDIX A
PART 556.
This section addresses leasing 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
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64453
TABLE H—DETAILED TABLE FOR PART 259
Current citation and BSEE citation
(if applicable)
Implementing bureau and BOEM
citation (if applicable)
Explanation
This section addresses definitions used in lease administration under
the authority of BOEM.
This section used in lease administration under the authority of
BOEM.
§ 259.001
Purpose and scope ......
Moved to BOEM, § 559.001 ..........
§ 259.002
Definitions ....................
Moved to BOEM, § 559.002 ..........
Part 260—Outer Continental Shelf Oil
and Gas Leasing—Moved to BOEM in Its
Entirety, Chapter V, Part 560
oversight of incentive-based royalty
relief and establishing royalty relief
thresholds.
BOEM is responsible for lease sales,
bidding systems, the regulatory
TABLE I—DETAILED TABLE FOR PART 260
Current citation and BSEE citation
(if applicable)
Implementing bureau and BOEM
citation (if applicable)
Explanation
Subpart A—General Provisions
§ 260.1 What is the purpose of
this part?
§ 260.2 What definitions apply to
this part?
§ 260.3 What is MMS’s authority
to collect information?
Moved to BOEM, § 560.1 ..............
Moved to BOEM, § 560.2 ..............
Moved to BOEM, § 560.3 ..............
This section addresses leasing activities on the OCS that are under
the authority of BOEM.
This section addresses leasing activities on the OCS that are under
the authority of BOEM.
This section addresses leasing activities on the OCS that are under
the authority of BOEM.
mstockstill on DSK4VPTVN1PROD with RULES2
Subpart B—Bidding Systems
§ 260.101 What is the purpose of
this subpart?
§ 260.102 What definitions apply
to this subpart?
§ 260.110 What bidding systems
may MMS use?
§ 260.111 What conditions apply
to the bidding systems that MMS
uses?
§ 260.112 How do royalty suspension volumes apply to eligible
leases?
§ 260.113 When does an eligible
lease qualify for a royalty suspension volume?
§ 260.114 How does MMS assign
and monitor royalty suspension
volumes for eligible leases?
§ 260.115 How long will a royalty
suspension volume for an eligible
lease be effective?
§ 260.116 How do I measure natural gas production on my eligible lease?
§ 260.120 How does royalty suspension apply to leases issued in
a sale held after November
2000?
§ 260.121 When does a lease
issued in a sale held after November 2000 get a royalty suspension?
§ 260.122 How long will a royalty
suspension volume be effective
for a lease issued in a sale held
after November 2000?
§ 260.123 How do I measure natural gas production for a lease
issued in a sale held after November 2000?
VerDate Mar<15>2010
16:55 Oct 17, 2011
Moved to BOEM, § 560.101 ..........
Moved to BOEM, § 560.102 ..........
Moved to BOEM, § 560.110 ..........
Moved to BOEM, § 560.111 ..........
This section addresses leasing
the authority of BOEM.
This section addresses leasing
the authority of BOEM.
This section addresses leasing
the authority of BOEM.
This section addresses leasing
the authority of BOEM.
activities on the OCS that are under
activities on the OCS that are under
activities on the OCS that are under
activities on the OCS that are under
Moved to BOEM, § 560.112 ..........
This section addresses leasing activities on the OCS that are under
the authority of BOEM.
Moved to BOEM, § 560.113 ..........
This section addresses leasing activities on the OCS that are under
the authority of BOEM.
Moved to BOEM, § 560.114 ..........
This section addresses leasing activities on the OCS that are under
the authority of BOEM.
Moved to BOEM, § 560.115 ..........
This section addresses leasing activities on the OCS that are under
the authority of BOEM.
Moved to BOEM, § 560.116 ..........
This section addresses leasing activities on the OCS that are under
the authority of BOEM.
Moved to BOEM, § 560.120 ..........
This section addresses leasing activities on the OCS that are under
the authority of BOEM.
Moved to BOEM, § 560.121 ..........
This section addresses leasing activities on the OCS that are under
the authority of BOEM.
Moved to BOEM, § 560.122 ..........
This section addresses leasing activities on the OCS that are under
the authority of BOEM.
Moved to BOEM, § 560.123 ..........
This section addresses leasing activities on the OCS that are under
the authority of BOEM.
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Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations
TABLE I—DETAILED TABLE FOR PART 260—Continued
Current citation and BSEE citation
(if applicable)
Implementing bureau and BOEM
citation (if applicable)
Explanation
§ 260.124 How will royalty suspension apply if MMS assigns a
lease issued in a sale held after
November 2000 to a field that
has a pre-Act lease?
§ 260.130 What
criteria
does
MMS use for selecting bidding
systems and bidding system
components?
Moved to BOEM, § 560.124 ..........
This section addresses leasing activities on the OCS that are under
the authority of BOEM.
Moved to BOEM, § 560.130 ..........
This section addresses leasing activities on the OCS that are under
the authority of BOEM.
Subpart C—[Reserved]
Subpart D—Joint Bidding
§ 260.301 What is the purpose of
this subpart?
§ 260.302 What definitions apply
to this subpart?
§ 260.303 What are the joint bidding requirements?
Moved to BOEM, § 560.301 ..........
Moved to BOEM, § 560.302 ..........
Moved to BOEM, § 560.303 ..........
This section addresses leasing activities on the OCS that are under
the authority of BOEM.
This section addresses leasing activities on the OCS that are under
the authority of BOEM.
This section 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
Current citation and BSEE citation
(if applicable)
Implementing bureau and BOEM
citation (if applicable)
Explanation
This section addresses the nondiscrimination on the OCS provisions
that are relevant to the activities regulated by both BSEE and
BOEM.
This section addresses the nondiscrimination on the OCS provisions
that are under the authority of both BSEE and BOEM.
This section addresses the nondiscrimination on the OCS provisions
that are under the authority of both BSEE and BOEM.
This section addresses the nondiscrimination on the OCS provisions
that are under the authority of both BSEE and BOEM.
This section addresses the nondiscrimination on the OCS provisions
that are under the authority of both BSEE and BOEM.
This section addresses the nondiscrimination on the OCS provisions
that are under the authority of both BSEE and BOEM.
This section addresses the nondiscrimination on the OCS provisions
that are under the authority of both BSEE and BOEM.
§ 270.1
Purpose ............................
Revised in both BSEE and BOEM
§ 570.1.
§ 270.2
Application of this part .....
§ 270.3
Definitions ........................
§ 270.4
Discrimination prohibited ..
§ 270.5
Complaint .........................
§ 270.6
Process ............................
§ 270.7
Remedies .........................
Revised in
§ 570.2.
Revised in
§ 570.3.
Revised in
§ 570.4.
Revised in
§ 570.5.
Revised in
§ 570.6.
Revised in
§ 570.7.
Part 280—Prospecting for Minerals
Other Than Oil, Gas, and Sulphur on
the Outer Continental Shelf—Moved to
both BSEE and BOEM
both BSEE and BOEM
both BSEE and BOEM
both BSEE and BOEM
both BSEE and BOEM
both BSEE and BOEM
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
mstockstill on DSK4VPTVN1PROD with RULES2
Current citation and BSEE citation
(if applicable)
Implementing bureau and BOEM
citation (if applicable)
Explanation
Subpart A—General Information
§ 280.1 What definitions apply to
this part?
§ 280.2 What is the purpose of
this part?
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Moved to BOEM, § 580.1 ..............
Moved to BOEM, § 580.2 ..............
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This section addresses activities within the scope of oil, gas and sulphur prospecting on the OCS under BOEM.
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TABLE K—DETAILED TABLE FOR PART 280—Continued
Current citation and BSEE citation
(if applicable)
Implementing bureau and BOEM
citation (if applicable)
Explanation
§ 280.3 What requirements must I
follow
when
I
conduct
prospecting or research activities?
§ 280.4 What activities are not
covered by this part?
Moved to BOEM, § 580.3 ..............
This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.
Moved to BOEM, § 580.4 ..............
This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.
Subpart B—How To Apply for a Permit or File a Notice
§ 280.10 What must I do before I
may conduct prospecting activities?
§ 280.11 What must I do before I
may conduct scientific research?
§ 280.12 What must I include in
my application or notification?
§ 280.13 Where must I send my
application or notification?
Moved to BOEM, § 580.10 ............
This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.
Moved to BOEM, § 580.11 ............
This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.
This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.
This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.
Moved to BOEM, § 580.12 ............
Moved to BOEM, § 580.13 ............
Subpart C—Obligations Under This Part
§ 280.20 What must I not do in
conducting Geological and Geophysical (G&G) prospecting or
scientific research?
§ 280.21 What must I do in conducting G&G prospecting or scientific research?
§ 280.22 What must I do when
seeking approval for modifications?
§ 280.23 How must I cooperate
with inspection activities?
§ 280.24 What reports must I file?
§ 280.25 When may MMS require
me to stop activities under this
part?
§ 280.26 When may I resume activities?
§ 280.27 When may MMS cancel
my permit?
§ 280.28 May I relinquish my permit?
§ 280.29 Will MMS monitor the
environmental effects of my activity?
§ 280.30 What activities will not
require environmental analysis?
§ 280.31 Whom will MMS notify
about environmental issues?
§ 280.32 What penalties may I be
subject to?
§ 280.33 How can I appeal a penalty?
§ 280.34 How can I appeal an
order or decision?
Moved to BOEM, § 580.20 ............
This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.
Moved to BOEM, § 580.21 ............
This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.
Moved to BOEM, § 580.22 ............
This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.
Moved to BOEM, § 580.23 ............
This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.
This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.
This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.
Moved to BOEM, § 580.24 ............
Moved to BOEM, § 580.25 ............
Moved to BOEM, § 580.26 ............
In
both BSEE and BOEM,
§ 580.27.
In both BSEE and BOEM,
§ 580.28.
Moved to BOEM, § 580.29 ............
Moved to BOEM, § 580.30 ............
Moved to BOEM, § 580.31 ............
Moved to BOEM, § 580.32 ............
Moved to BOEM, § 580.33 ............
Moved to BOEM, § 580.34 ............
This section addresses activities within the scope
phur prospecting on the OCS under BOEM.
This section addresses activities within the scope
phur prospecting on the OCS under BOEM.
This section addresses activities within the scope
phur prospecting on the OCS under BOEM.
This section addresses activities within the scope
phur prospecting on the OCS under BOEM.
of oil, gas, and sul-
This section addresses activities within the scope
phur prospecting on the OCS under BOEM.
This section addresses activities within the scope
phur prospecting on the OCS under BOEM.
This section addresses activities within the scope
phur prospecting on the OCS under BOEM.
This section addresses activities within the scope
phur prospecting on the OCS under BOEM.
This section addresses activities within the scope
phur prospecting on the OCS under BOEM.
of oil, gas, and sul-
of oil, gas, and sulof oil, gas, and sulof oil, gas, and sul-
of oil, gas, and sulof oil, gas, and sulof oil, gas, and sulof oil, gas, and sul-
mstockstill on DSK4VPTVN1PROD with RULES2
Subpart D—Data Requirements
§ 280.40 When do I notify MMS
that geological data and information are available for submission,
inspection, and selection?
§ 280.41 What types of geological
data and information must I submit to MMS?
§ 280.42 When geological data
and information are obtained by
a third party, what must we both
do?
VerDate Mar<15>2010
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Moved to BOEM, § 580.40 ............
This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.
Moved to BOEM, § 580.41 ............
This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.
Moved to BOEM, § 580.42 ............
This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.
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TABLE K—DETAILED TABLE FOR PART 280—Continued
Current citation and BSEE citation
(if applicable)
Implementing bureau and BOEM
citation (if applicable)
Explanation
§ 280.50 When do I notify MMS
that geophysical data and information are available for submission, inspection, and selection?
§ 280.51 What types of geophysical data and information
must I submit to MMS?
§ 280.52 When geophysical data
and information are obtained by
a third party, what must we both
do?
§ 280.60 Which of my costs will
be reimbursed?
§ 280.61 Which of my costs will
not be reimbursed?
§ 280.70 What data and information will be protected from public
disclosure?
§ 280.71 What is the timetable for
release of data and information?
§ 280.72 What
procedure
will
MMS follow to disclose acquired
data and information to a contractor for reproduction, processing, and interpretation?
§ 280.73 Will MMS share data
and information with coastal
States?
Moved to BOEM, § 580.50 ............
This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.
Moved to BOEM, § 580.51 ............
This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.
Moved to BOEM, § 580.52 ............
This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.
Moved to BOEM, § 580.60 ............
This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.
This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.
This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.
Moved to BOEM, § 580.61 ............
Moved to BOEM, § 580.70 ............
Moved to BOEM, § 580.71 ............
Moved to BOEM, § 580.72 ............
This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.
This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.
Moved to BOEM, § 580.73 ............
This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.
Subpart E—Information Collection
§ 280.80 Paperwork
Reduction
Act statement—information collection
Moved to BOEM, § 580.80 ............
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
This section addresses activities within the scope of oil, gas and sulphur prospecting on the OCS under BOEM.
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
Current citation and BSEE citation
(if applicable)
Implementing bureau and BOEM
citation (if applicable)
Explanation
Subpart A—General
Moved to BOEM, § 581.1 ..............
§ 281.2
Authority ...........................
Moved to BOEM, § 581.2 ..............
§ 281.3
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§ 281.0 Authority for information
collection.
§ 281.1 Purpose and applicability
Definitions ........................
Moved to BOEM, § 581.3 ..............
§ 281.4
Qualifications of lessees ..
Moved to BOEM, § 581.4 ..............
§ 281.5
False statements ..............
Moved to BOEM, § 581.5 ..............
§ 281.6
Appeals ............................
Moved to BOEM, § 581.6 ..............
§ 281.7 Disclosure of information
to the public.
Moved to BOEM, § 581.7 ..............
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This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
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64457
TABLE L—DETAILED TABLE FOR PART 281—Continued
Current citation and BSEE citation
(if applicable)
Implementing bureau and BOEM
citation (if applicable)
Explanation
This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
§ 281.8
Rights to minerals ............
Moved to BOEM, § 581.8 ..............
§ 281.9
sies.
Jurisdictional
Moved to BOEM, § 581.9 ..............
controver-
Subpart B—Leasing Procedures
§ 281.11 Unsolicited request for a
lease sale.
§ 281.12 Request for OCS mineral
information and interest.
§ 281.13 Joint State/Federal coordination.
§ 281.14 OCS mining area identification.
§ 281.15 Tract size .......................
Moved to BOEM, § 581.11 ............
Moved to BOEM, § 581.15 ............
§ 281.16
Proposed leasing notice
Moved to BOEM, § 581.16 ............
§ 281.17
Leasing notice ................
Moved to BOEM, § 581.17 ............
§ 281.18
Bidding system ...............
Moved to BOEM, § 581.18 ............
§ 281.19
Lease term .....................
Moved to BOEM, § 581.19 ............
§ 281.20
Submission of bids .........
Moved to BOEM, § 581.20 ............
§ 281.21
Award of leases .............
Moved to BOEM, § 581.21 ............
§ 281.22
Lease form .....................
Moved to BOEM, § 581.22 ............
§ 281.23
Effective date of leases
Moved to BOEM, § 581.23 ............
Moved to BOEM, § 581.12 ............
Moved to BOEM, § 581.13 ............
Moved to BOEM, § 581.14 ............
This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
Subpart C—Financial Considerations
§ 281.26
Payments .......................
Moved to BOEM, § 581.26 ............
§ 281.27
Annual rental ..................
Moved to BOEM, § 581.27 ............
§ 281.28
Royalty ...........................
Moved to BOEM, § 581.28 ............
§ 281.29
Royalty valuation ............
Moved to BOEM, § 581
§ 281.30
Minimum royalty .............
Moved to BOEM, § 581.30 ............
§ 281.31
Overriding royalties ........
Moved to BOEM, § 581.31 ............
§ 281.32 Waiver, suspension, or
reduction of rental, minimum royalty or production royalty.
§ 281.33 Bonds and bonding requirements.
Moved to BOEM, § 581.32 ............
29 ..........
Moved to BOEM, § 581.33 ............
This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
mstockstill on DSK4VPTVN1PROD with RULES2
Subpart D—Assignments and Lease Extensions
§ 281.40 Assignment of leases or
interests therein.
§ 281.41 Requirements for filing
for transfers.
§ 281.42 Effect of assignment on
particular lease.
§ 281.43 Effect of suspensions on
lease term.
Moved to BOEM, § 581.40 ............
Moved to BOEM, § 581.41 ............
Moved to BOEM, § 581.42 ............
Moved to BOEM, § 581.43 ............
This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
This section 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
§ 281.46 Relinquishment of leases
or parts of leases.
§ 281.47 Cancellation of leases ....
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Moved to BOEM, § 581.46 ............
Moved to BOEM, § 581.47 ............
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This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
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Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations
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
Current citation and BSEE citation
(if applicable)
Implementing bureau and BOEM
citation (if applicable)
Explanation
Subpart A—General
§ 282.0 Authority for information
collection.
§ 282.1 Purpose and authority ......
§ 282.2 Scope ...............................
§ 282.3 Definitions ........................
§ 282.4 Opportunities for review
and comment.
§ 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.
Both BSEE and BOEM § 582.0 .....
Both agencies need the authority for information collection.
Both BSEE and BOEM § 582.1 .....
Both BSEE and BOEM § 582.2 .....
Both BSEE and BOEM § 582.3 .....
Moved to BOEM, § 582.4 ..............
Needed by both agencies.
Needed by both agencies.
Needed by both agencies.
BOEM responsibility.
Both BSEE and BOEM § 582.5 .....
Needed by both agencies.
Both BSEE and BOEM § 582.6 .....
Needed by both agencies.
Both BSEE and BOEM § 582.7 .....
Needed by both agencies.
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 Cancellation of leases ....
Both BSEE and BOEM § 582.10 ...
Needed by both agencies.
Moved to BOEM, § 582.11. Paragraph (d) on mining units is in
both.
Responsibilities are shared by
both BSEE and BOEM.
Paragraph (d) involves units, which is a BSEE function. Paragraph
(d) also contains BOEM responsibilities as it mentions plans.
Retained in BSEE ..........................
Both BSEE and BOEM § 582.14 ...
Moved to BOEM, § 582.15 ............
Paragraphs (a), (e), (f), and (h) are retained in BSEE. 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.
Suspensions are under the authority of BSEE.
BSEE is responsible for addressing noncompliance, remedies, and
penalties. Needed in both agencies.
BOEM is responsible for lease administration.
Subpart C—Obligations and Responsibilities of Lessees
§ 282.20 Obligations and responsibilities of lessees.
§ 282.21 Plans, general ................
mstockstill on DSK4VPTVN1PROD with RULES2
§ 282.22
§ 282.23
§ 282.24
§ 282.25
§ 282.26
§ 282.27
Delineation Plan .............
Testing Plan ...................
Mining Plan ....................
Plan modification ............
Contingency Plan ...........
Conduct of operations ....
§ 282.28 Environmental protection
measures.
§ 282.29
§ 282.30
ment.
Reports and records ......
Right of use and ease-
VerDate Mar<15>2010
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Moved to BOEM, § 582.20 ............
Moved to BOEM, § 582.21, except
paragraph (e), which is in both.
Moved to BOEM, § 582.22 ............
Moved to BOEM, § 582.23 ............
Moved to BOEM, § 582.24 ............
Moved to BOEM, § 582.25 ............
Moved to BOEM, § 582.26 ............
Retained in BSEE. Paragraph (i)
also in BOEM, § 582.27.
Moved to BOEM § 582.28. Paragraphs (c)(1), (c)(2), (c)(3),
(c)(4) and (c)(6), and (d) are retained in BSEE. Paragraphs
(c)(2) and (c)(6) are in both.
Moved to BOEM, § 582.29 ............
Moved to BOEM, § 582.30 ............
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This section addresses obligations and responsibilities of lessees that
are the responsibility of BOEM.
This section addresses plans that are the responsibility of 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.
This section addresses plans that are the responsibility of BOEM.
This section addresses plans that are the responsibility of BOEM.
This section addresses plans that are the responsibility of BOEM.
This section addresses plans that are the responsibility of BOEM.
This section addresses plans that are the responsibility of BOEM.
Paragraph (i) addresses plans that are the responsibility of BOEM.
Paragraphs (c)(1), (c)(3) and (c)(4) pertain to mitigation, observations, and testing activities. Paragraph (d) describes ways to minimize environmental impacts. Overseeing these activities is a BSEE
responsibility. Both BOEM and BSEE have discrete monitoring
functions under (c)(2) and (c)(6).
A resource evaluation function under BOEM.
BOEM has the authority to grant rights of use and easement.
Sfmt 4700
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Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations
TABLE M—DETAILED TABLE FOR PART 282—Continued
Current citation and BSEE citation
(if applicable)
Implementing bureau and BOEM
citation (if applicable)
§ 282.31 Suspension of production or other operations.
Retained in BSEE ..........................
Explanation
BSEE has the authority to suspend production or other operations.
Subpart D—Payments
§ 282.40
Bonds .............................
Moved to BOEM, § 582.40 ............
§ 282.41 Method of royalty calculation.
Both BSEE and BOEM, § 582.41 ..
§ 282.42
Moved to BOEM, § 582.42 ............
Payments .......................
Financial assurance is a BOEM function with a cross reference provided for BSEE.
ONRR regulations at 30 CFR part 1206 may apply. Otherwise, lessees must comply with BOEM’s procedures specified in lease notices.
BOEM.
Subpart E—Appeals
§ 282.50
Appeals ..........................
Both BSEE and BOEM, § 582.50 ..
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.
Both agencies need the procedures for addressing appeals.
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 BSEE citation
(if applicable)
Implementing bureau and BOEM
citation (if applicable)
Explanation
Subpart A—Offshore Minerals Management Appeal Procedures
§ 290.1 What is the purpose of
this subpart?
§ 290.2 Who may appeal?
Both BSEE and BOEM § 590.1 .....
§ 290.3 What is the time limit for
filing an appeal?
§ 290.4 How do I file an appeal?
Both BSEE and BOEM § 590.3 .....
§ 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?
Both BSEE and BOEM § 590.5 .....
Both BSEE and BOEM § 590.2 .....
Both BSEE and BOEM § 590.4 .....
Both BSEE and BOEM § 590.6 .....
Both BSEE and BOEM § 590.7 .....
Both BSEE and BOEM § 590.8 .....
Both BSEE and BOEM need to provide opportunity for
cisions.
Both BSEE and BOEM need to provide opportunity for
cisions.
Both BSEE and BOEM. need to provide opportunity
decisions.
Both BSEE and BOEM need to provide opportunity for
cisions.
Both BSEE and BOEM need to provide opportunity for
cisions.
Both BSEE and BOEM need to provide opportunity for
cisions.
Both BSEE and BOEM need to provide opportunity for
cisions.
appeals of deappeals of defor appeals of
appeals of deappeals of deappeals of deappeals of de-
Both BSEE and BOEM need to provide opportunity for appeals of 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
mstockstill on DSK4VPTVN1PROD with RULES2
TABLE O—DETAILED TABLE FOR PART 291
Current citation and BSEE citation
(if applicable)
Implementing bureau and BOEM
citation (if applicable)
Justification
SUBCHAPTER C—APPEALS
§ 291.1 What is MMS’s authority
to collect information?
VerDate Mar<15>2010
16:55 Oct 17, 2011
Retained in its entirety in BSEE,
chapter II.
Jkt 226001
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This section addresses information collection authority for open and
nondiscriminatory access to oil and gas pipelines under OCSLA.
Offshore operations are under the authority of BSEE.
Sfmt 4700
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Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations
TABLE O—DETAILED TABLE FOR PART 291—Continued
Current citation and BSEE citation
(if applicable)
Implementing bureau and BOEM
citation (if applicable)
Justification
§ 291.100 What is the purpose of
this part?
Retained in its entirety in BSEE,
chapter II.
§ 291.101 What definitions apply
to this part?
Retained in its entirety in BSEE,
chapter II.
§ 291.102 May I call the MMS
Hotline to informally resolve an
allegation that open and nondiscriminatory access was denied?
§ 291.103 May I use alternative
dispute resolution to informally
resolve an allegation that open
and nondiscriminatory access
was denied?
§ 291.104 Who may file a complaint or a third-party brief?
Retained in its entirety in BSEE,
chapter II.
This section addresses purpose of open and nondiscriminatory access to oil and gas pipelines under OCSLA. Offshore operations
are under the authority of BSEE.
This section addresses the definitions that pertain to open and nondiscriminatory access to oil and gas pipelines under OCSLA. Offshore operations are under the authority of BSEE.
This section addresses open and nondiscriminatory access to oil and
gas pipelines under OCSLA. Offshore operations are under the authority of BSEE.
§ 291.105 What must a complaint
contain?
Retained in its entirety in BSEE,
chapter II.
§ 291.106
plaint?
How do I file a com-
Retained in its entirety in BSEE,
chapter II.
§ 291.107 How do I answer a
complaint?
Retained in its entirety in BSEE,
chapter II.
§ 291.108 How do I pay the processing fee?
Retained in its entirety in BSEE,
chapter II.
§ 291.109 Can I ask for a fee
waiver or a reduced processing
fee?
§ 291.110 Who may MMS require
to produce information?
Retained in its entirety in BSEE,
chapter II.
§ 291.111 How does MMS treat
the confidential information I provide?
§ 291.112 What process will MMS
follow in rendering a decision on
whether a grantee or transporter
has provided open and nondiscriminatory access?
§ 291.113 What actions may MMS
take to remedy denial of open
and nondiscriminatory access?
§ 291.114 How do I appeal to the
IBLA?
Retained in its entirety in BSEE,
chapter II.
§ 291.115 How do I exhaust administrative remedies?
Retained in its entirety in BSEE,
chapter II.
Retained in its entirety in BSEE,
chapter II.
This section addresses open and nondiscriminatory access to oil and
gas pipelines under OCSLA. Offshore operations are under the authority of BSEE.
Retained in its entirety in BSEE,
chapter II.
This section addresses open and nondiscriminatory access to oil and
gas pipelines under OCSLA. Offshore operations are under the authority of BSEE.
This section addresses open and nondiscriminatory access to oil and
gas pipelines under OCSLA. Offshore operations are under the authority of BSEE.
This section addresses open and nondiscriminatory access to oil and
gas pipelines under OCSLA. Offshore operations are under the authority of BSEE.
This section addresses open and nondiscriminatory access to oil and
gas pipelines under OCSLA. Offshore operations are under the authority of BSEE.
This section addresses open and nondiscriminatory access to oil and
gas pipelines under OCSLA. Offshore operations are under the authority of BSEE.
This section addresses open and nondiscriminatory access to oil and
gas pipelines under OCSLA. Offshore operations are under the authority of BSEE.
This section addresses open and nondiscriminatory access to oil and
gas pipelines under OCSLA. Offshore operations are under the authority of BSEE.
This section addresses open and nondiscriminatory access to oil and
gas pipelines under OCSLA. Offshore operations are under the authority of BSEE.
This section addresses open and nondiscriminatory access to oil and
gas pipelines under OCSLA. Offshore operations are under the authority of BSEE.
Retained in its entirety in BSEE,
chapter II.
Retained in its entirety in BSEE,
chapter II.
Retained in its entirety in BSEE,
chapter II.
Retained in its entirety in BSEE,
chapter II.
Procedural Matters
mstockstill on DSK4VPTVN1PROD with RULES2
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.
VerDate Mar<15>2010
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Jkt 226001
This section addresses open and nondiscriminatory access to oil and
gas pipelines under OCSLA. Offshore operations are under the authority of BSEE.
This section addresses open and nondiscriminatory access to oil and
gas pipelines under OCSLA. Offshore operations are under the authority of BSEE.
This section addresses open and nondiscriminatory access to oil and
gas pipelines under OCSLA. Offshore operations are under the authority of BSEE.
(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.
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(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
E:\FR\FM\18OCR2.SGM
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Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations
Civil Justice Reform (E.O. 12988)
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.
mstockstill on DSK4VPTVN1PROD with RULES2
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.
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16:55 Oct 17, 2011
Jkt 226001
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.
64461
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—rightsof-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.
Data Quality Act
30 CFR Part 282
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).
Administrative practice and
procedure, Continental shelf,
Environmental protection, Government
contracts, Intergovernmental relations,
Mineral royalties, Penalties, Public
lands—mineral resources, Reporting
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Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations
and recordkeeping requirements, Surety
bonds.
30 CFR Part 290
Administrative practice and
procedure.
30 CFR Part 291
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.
Administrative practice and
procedure, Civil rights, Continental
shelf, Government contracts, Oil and gas
exploration, Public lands—mineral
resources.
30 CFR Part 519
Continental shelf, Government
contracts, Indians—lands, Mineral
royalties, Oil and gas exploration,
Public lands—mineral resources,
Sulphur.
30 CFR Part 580
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, 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
Continental shelf, Freedom of
information, Oil and gas exploration,
Public lands—mineral resources,
Reporting and recordkeeping
requirements, Research.
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 552
Continental shelf, Freedom of
information, Intergovernmental
relations, Oil and gas exploration,
Public lands—mineral resources,
Reporting and recordkeeping
requirements.
30 CFR Part 585
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—rightsof-way, Reporting and recordkeeping
requirements, Surety bonds.
Continental shelf, Government
contracts, Mineral royalties, Oil and gas
exploration, Public lands—mineral
resources.
16:55 Oct 17, 2011
Jkt 226001
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
30 CFR Part 590
PART 203—RELIEF OR REDUCTION IN
ROYALTY RATES
Administrative practice and
procedure.
Subpart A—General Provisions
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:
30 CFR Part 559
VerDate Mar<15>2010
CHAPTER II—BUREAU OF SAFETY AND
ENVIRONMENTAL ENFORCEMENT,
DEPARTMENT OF THE INTERIOR
Continental shelf, Environmental
protection, Incorporation by reference,
Public lands.
30 CFR Part 553
mstockstill on DSK4VPTVN1PROD with RULES2
30 CFR Part 560
TITLE 30—MINERAL RESOURCES
1. Chapter II is revised to read as
follows:
■
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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?
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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?
mstockstill on DSK4VPTVN1PROD with RULES2
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 endof-life royalty relief arrangement for an
oil and gas lease be ended?
203.56 Does relief transfer when a lease is
assigned?
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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?
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64463
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
§ 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
§ 203.47.
Complete application means an
original and two copies of the six
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reports consisting of the data specified
in §§ 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:
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(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, tensionleg 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
§§ 203.30 through 203.36 or §§ 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 § 203.49
to replace the lease terms for royalty
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relief with those in § 203.0 and
§§ 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 nonconverted 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
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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 § 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 § 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
§ 203.35 or § 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 § 203.35.
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Qualified well means either a
qualified deep well or a qualified ultradeep 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
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64465
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 reperforated less than 20,000 feet TVD SS
in the same reservoir is still an ultradeep 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.
§ 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);
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(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.
§ 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.
If you have a lease . . .
And if you . . .
Then we may grant you . . .
(a) With earnings that cannot sustain production (i.e., End-of-life lease),
Would abandon otherwise potentially recoverable resources but seek to increase production by operating beyond the point at which
the lease is economic under the existing
royalty rate,
Propose an expansion project and can demonstrate your project is uneconomic without
royalty relief,
A reduced royalty rate on current monthly production and a higher royalty rate on additional monthly production (see §§ 203.50
through 203.56).
(b) Located in a designated GOM deep water
area (i.e., 200 meters or greater) and acquired in a lease sale held before November
28, 1995, or after November 28, 2000,
(c) Located in a designated GOM deep water
area and acquired in a lease sale held before
November 28, 1995 (Pre-Act lease),
(d) Located in a designated GOM deep water
area and acquired in a lease sale held after
November 28, 2000,
(e) Where royalty relief would recover significant additional resources or, offshore Alaska
or in certain areas of the GOM, would enable
development,
(f) Located in a designated GOM shallow water
area and acquired in a lease sale held before
January 1, 2001, or after January 1, 2004, or
have exercised an option to substitute for
royalty relief in your lease terms,
(g) Located in a designated GOM shallow water
area,
(h) Located in planning areas offshore Alaska,
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§ 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.
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Are on a field from which no current pre-Act
lease produced (other than test production)
before November 28, 1995, (Authorized
field,)
Propose a development project and can demonstrate that the suspension volume, if any,
for your lease is not enough to make development economic,
Are not eligible to apply for end-of-life or deep
water royalty relief, but show us you meet
certain eligibility conditions,
Drill a deep well on a lease that is not eligible
for deep water royalty relief and you have
not previously produced oil or gas from a
deep well or an ultra-deep well,
Drill and produce gas from an ultra-deep well
on a lease that is not eligible for deep water
royalty relief and you have not previously
produced oil or gas from an ultra-deep well,
Propose an expansion project or propose a
development project and can demonstrate
that the project is uneconomic without relief
or that the suspension volume, if any, for
your lease is not enough to make development economic,
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
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A royalty suspension for a minimum production volume plus any additional production
large enough to make the project economic
(see §§ 203.60 through 203.79).
A royalty suspension for a minimum production volume plus any additional volume
needed to make the field economic (see
§§ 203.60 through 203.79).
A royalty suspension for a minimum production volume plus any additional volume
needed to make your project economic (see
§§ 203.60 through 203.79).
A royalty modification in size, duration, or
form that makes your lease or project economic (see § 203.80).
A royalty suspension for a volume of gas produced from successful deep and ultra-deep
wells, or, for certain unsuccessful deep and
ultra-deep wells, a smaller royalty suspension for a volume of gas or oil produced by
all wells on your lease (see §§ 203.40
through 203.49).
A royalty suspension for a volume of gas produced from successful ultra-deep and deep
wells on your lease (see §§ .203.30 through
203.36).
A royalty suspension for a minimum production volume plus any additional volume
needed to make your project economic (see
§§ 203.60, 203.62, 203.67 through 203.70,
203.73, and 203.76 through 203.79).
Pay.gov Web site may be accessed
through a link on the BSEE Offshore
Web site at: https://www.bsee.gov/
offshore/ homepage or directly through
Pay.gov at: https://www.pay.gov/
paygov/.
§ 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-oflife and deep water royalty relief
programs in §§ 203.50 to 203.91.
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Because royalty relief for deep gas on
leases not subject to deep water royalty
relief, as provided for under §§ 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
64467
§§ 203.51, 203.62, and 203.81 through
203.89 for applications for royalty relief.
Deep water
Information elements
End-of-life
lease
(1) Administrative information report ...............................................................................
(2) Net revenue and relief justification report (prescribed format) ..................................
(3) Economic viability and relief justification report (Royalty Suspension Viability Program (RSVP) model inputs justified with Geological and Geophysical (G&G), Engineering, Production, & Cost reports) ...........................................................................
(4) G&G report .................................................................................................................
(5) Engineering report ......................................................................................................
(6) Production report ........................................................................................................
(7) Deep water cost report ..............................................................................................
(b) We require the confirmation
elements indicated by an X in the
following table and described in
Expansion
project
Pre-act
lease
Development
project
X
X
X
..................
X
..................
X
......................
......................
......................
......................
......................
......................
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
§§ 203.70, 203.81, 203.90 and 203.91 to
retain royalty relief.
Deep water
Confirmation elements
End-of-life
lease
(1) Fabricator’s confirmation report .................................................................................
(2) Post-production development report approved by an independent certified public
accountant (CPA) * * * ...............................................................................................
(c) The following table indicates by an
X, and §§ 203.50, 203.52, 203.60 and
203.67 describe, the prerequisites for
Expansion
project
Pre-act
lease
Development
project
......................
X
X
X
......................
X
X
X
our approval of your royalty relief
application.
Deep water
End-of-life
lease
Approval conditions
(1)
(2)
(3)
(4)
(5)
(6)
At least 12 of the last 15 months have the required level of production ..................
Already producing ......................................................................................................
A producible well into a reservoir that has not produced before ...............................
Royalties for qualifying months exceed 75 percent of net revenue (NR) .................
Substantial investment on a pre-Act lease (e.g., platform, subsea template) ...........
Determined to be economic only with relief ...............................................................
(d) The following table indicates by
an X, and §§ 203.52, 203.74, and 203.75
describe, the prerequisites for a
Expansion
Pre-act
lease
Development
project
X
X
......................
X
......................
......................
..................
..................
X
..................
..................
X
..................
..................
X
..................
..................
X
......................
......................
X
......................
......................
X
redetermination of our royalty relief
decision.
Deep water
End-of-life
lease
(1) After 12 months under current rate, criteria same as for approval ...........................
(2) For material change in geologic data, prices, costs, or available technology ...........
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Redetermination conditions
X
......................
(e) The following table indicates by an
X, and §§ 203.53 and 203.69 describe,
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Expansion
project
Pre-act
lease
Development
project
..................
X
..................
X
......................
X
the characteristics of approved royalty
relief.
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Deep water
End-of-life
lease
Relief rate and volume, subject to certain conditions
(1) One-half pre-application effective lease rate on 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 production for 12 qualifying months ......
(3) Zero royalty rate on the suspension volume and the original lease rate on additional production ...........................................................................................................
(4) Suspension volume is at least 17.5, 52.5 or 87.5 million barrels of oil equivalent
(MMBOE) .....................................................................................................................
(5) Suspension volume is at least the minimum set in the Notice of Sale, the lease, or
the regulations ..............................................................................................................
(6) Amount needed to become economic .......................................................................
(f) The following table indicates by an
X, and §§ 203.54 and 203.78 describe,
Expansion
project
Pre-act
lease
Development
project
X
X
..................
..................
..................
..................
......................
......................
......................
X
X
X
......................
..................
X
......................
......................
......................
X
X
..................
X
X
X
circumstances under which we
discontinue your royalty relief.
Deep water
End-of-life
lease
Full royalty resumes when
(1) Average NYMEX price for last 12 months is at least 25 percent above the average for the qualifying months. .....................................................................................
(2) Average NYMEX price for last calendar year exceeds $28/bbl or $3.50/mcf, escalated by the gross domestic product (GDP) deflator since 1994 ................................
(3) Average prices for designated periods exceed levels we specify in the Notice of
Sale or the lease ..........................................................................................................
(g) The following table indicates by an
X, and §§ 203.55, 203.76, and 203.77
Expansion
project
Pre-act
lease
Development
project
X
..................
..................
......................
......................
X
X
......................
......................
X
..................
X
describe, circumstances under which
we end or reduce royalty relief.
Deep water
Relief withdrawn or reduced
End-of-life
lease
(1) If recipient requests ....................................................................................................
(2) Lease royalty rate is at the effective rate for 12 consecutive months .......................
(3) Conditions occur that we specified in the approval letter in individual cases ...........
(4) Recipient does not submit post-production report that compares expected to actual costs ......................................................................................................................
(5) Recipient changes development system ...................................................................
(6) Recipient excessively delays starting fabrication .......................................................
(7) Recipient spends less than 80 percent of proposed pre-production costs prior to
start of production ........................................................................................................
(8) Amount of relief volume is produced .........................................................................
mstockstill on DSK4VPTVN1PROD with RULES2
§ 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
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Expansion
project
Pre-act
lease
Development
project
X
X
X
X
..................
..................
X
..................
..................
X
......................
......................
......................
......................
......................
X
X
X
X
X
X
X
X
X
......................
......................
X
X
X
X
X
X
proprietary under applicable law and
under regulations at § 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
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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
§ 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
§§ 203.31 through 203.36 if the lease
meets all the requirements of this
section.
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(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 § 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 §§ 203.60
through 203.79.
64469
§ 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 § 203.35 and the price
conditions in § 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 § 203.33:
If you have a qualified phase 2 or qualified phase 3 ultra-deep well
that is:
Then your lease earns an RSV on this volume of gas production:
(1) An original well,
(2) A sidetrack with a sidetrack measured depth of at least 20,000 feet,
(3) An ultra-deep short sidetrack that is a phase 2 ultra-deep well,
35 BCF.
35 BCF.
4 BCF plus 600 MCF times
sidetrack measured depth (rounded to the nearest 100 feet) but no
more than 25 BCF.
0 BCF.
(4) An ultra-deep short sidetrack that is a phase 3 ultra-deep well,
(b)(1) This paragraph applies if your
lease:
(i) Has produced gas or oil from a
deep well with a perforated interval the
top of which is less than 18,000 feet
TVD SS;
(ii) Was issued in a lease sale held
between January 1, 2004, and December
31, 2005; and
(iii) The terms of your lease expressly
incorporate the provisions of §§ 203.41
through 203.47 as they existed at the
time the lease was issued.
(2) Subject to the administrative
requirements of § 203.35 and the price
conditions in § 203.36, your qualified
well earns your lease an RSV shown in
the following table in BCF or MCF as
prescribed in § 203.33:
If you have a qualified phase 2 ultra-deep well that is . . .
Then your lease earns an RSV on this volume of gas production:
(i) An original well or a sidetrack with a sidetrack measured depth of at
least 20,000 feet TVD SS,
(ii) An ultra-deep short sidetrack,
10 BCF.
mstockstill on DSK4VPTVN1PROD with RULES2
(c) Lessees may request a refund of or
recoup royalties paid on production
from qualified phase 2 or phase 3 ultradeep wells that:
(1) Occurs before December 18, 2008,
and
(2) Is subject to application of an RSV
under either § 203.31 or § 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
§ 203.30(a)), has no existing deep or
ultra-deep wells and that the price
thresholds prescribed in § 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 § 203.30(c)), your lease is
eligible (according to § 203.30(b)) to earn an
RSV under § 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
§ 203.31(a), your 25,000 foot well qualifies
your lease for this RSV because the well was
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4 BCF plus 600 MCF times sidetrack measured depth (rounded to the
nearest 100 feet) but no more than 10 BCF.
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 § 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 (§ 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
§ 203.33(a)(2), or § 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 § 203.0)
because you spudded the well before the
publication date (May 18, 2007) of the
proposed rule when royalty relief under
§ 203.31(a) became effective. However, this
ultra-deep well may earn an RSV of 25 BCF
for your lease under § 203.41 (that became
effective May 3, 2004), if the lease is located
in water depths partly or entirely less than
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200 meters and has not previously produced
from a deep well (§ 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 § 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 § 203.0) and because the existence of
the 16,000-foot well means the lease is not
eligible (see § 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 § 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
§ 203.30 and the well fits the definition of a
phase 2 ultra-deep well (in § 203.0). Then in
2010, you spud and produce from a deep
well with a perforated interval the top of
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Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations
which is 16,000 feet TVD SS. Your 16,000foot well earns no RSV because it is on a
lease that already has a producing well at
least 18,000 feet subsea (see § 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
§ 203.33(a)(2), or § 203.33(b)(2) if your lease
is part of a unit and § 203.43(a)(2), or
§ 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 § 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 § 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 § 203.0 when it begins
producing, but your lease earns no additional
RSV under this section or § 203.41 because
it is on a lease that already has production
from a deep well (see § 203.30(b)). Both the
qualified deep well and the qualified ultradeep well would share your lease’s total RSV
of 15 BCF in the manner prescribed in
§§ 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 § 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 § 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 ultradeep well (production begins before the
expiration date for the pre-existing relief in
its water depth category) and an ultra-deep
short sidetrack in § 203.0. However, if it does
not begin production until 2010, it earns no
RSV because it is too short as a phase 3 ultradeep well to be a qualified ultra-deep well.
Example 7: Your lease was issued in June
2004 and expressly incorporates the
provisions of §§ 203.41 through 203.47 as
they existed at that time. In January 2005,
you spud a deep well (well no. 1) with a
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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 § 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.
§ 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 § 203.31 is
in addition to any royalty suspension
supplement (RSS) for your lease under
§ 203.45 that results from a different
wellbore.
(d) If your lease earns an RSV under
§ 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
§ 203.31 to production from the nonqualified well.
(e) You owe minimum royalties or
rentals in accordance with your lease
terms notwithstanding any RSVs
allowed under paragraphs (a) and (b) of
§ 203.31.
(f) Unused RSVs transfer to a
successor lessee and expire with the
lease.
§ 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 § 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
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Fmt 4701
Sfmt 4700
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 § 203.36, you must
apply the RSV prescribed in § 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
§ 203.35 or § 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 § 203.36, you must apply
the RSV prescribed in § 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 nonunitized area of your lease, regardless of
their depth, for which you have met the
requirements in § 203.35 or § 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 § 203.35 or § 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 nonunitized portion of lease A that earns lease
A an RSV of 35 BCF under § 203.31, one
qualified deep well on the unitized portion
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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
§ 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 § 203.31
or § 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.
§ 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 § 203.31:
(a) To production from completions
less than 15,000 feet TVD SS, except in
cases where the qualified well is reperforated 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
§ 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.
§ 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 § 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
64471
(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.
§ 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 § 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 § 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 § 203.31(b) by a phase 2 ultra-deep well.
(i) Any RSV earned under § 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 § 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 § 203.31(a)
by a phase 2 ultra-deep well on a non-converted lease;
(iv) Any RSV earned under § 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 § 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.
(i) The first 20 BCF of RSV earned by a well that is located on a nonconverted lease issued in OCS Lease Sale 178.
mstockstill on DSK4VPTVN1PROD with RULES2
(2) $4.55 per MMBtu,
(3) $4.08 per MMBtu,
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Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations
A price threshold in year 2007 dollars of . . .
Applies to . . .
(4) $5.83 per MMBtu,
(i) The first 20 BCF of RSV earned by a well that is located on a nonconverted lease issued in OCS Lease Sales 180, 182, 184, 185, or
187.
mstockstill on DSK4VPTVN1PROD with RULES2
(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 § 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 § 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
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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 ultradeep well (see definition in § 203.0), and
would earn the lease an RSV of 35 BCF under
§§ 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
§ 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
§§ 203.41 through 203.44, and may
receive an RSS under §§ 203.45 through
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Frm 00042
Fmt 4701
Sfmt 4700
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 § 203.49; or
(3) On or after January 1, 2004, and
the lease terms provide for royalty relief
under §§ 203.41 through 203.47. (Note:
Because the original § 203.41 has been
divided into new §§ 203.41 and 203.42
and subsequent sections have been
redesignated as §§ 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 §§ 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 §§ 203.60
through 203.79.
§ 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 § 203.40 and the
requirements in the following table.
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If your lease has not . . .
And if it later . . .
Then your lease . . .
(1) produced gas or oil from any deep well or
ultra-deep well,
(2) produced gas or oil from a well with a perforated interval whose top is 18,000 feet TVD
SS or deeper,
Has a qualified deep well or qualified phase 1
ultra-deep well,
Has a qualified deep well with a perforated interval whose top is 18,000 feet TVD SS or
deeper or a qualified phase 1 ultra-deep
well,
earns
this
earns
this
64473
(b) If your lease meets the
requirements in paragraph (a)(1) of this
an RSV specified in paragraph (b) of
section.
an RSV specified in paragraph (c) of
section.
section, it earns the RSV prescribed in
the following table:
If you have a qualified deep well or a qualified phase 1 ultra-deep well
that is:
Then your lease earns an RSV on this volume of gas production:
(1) An original well with a perforated interval the top of which is
15,000 to less than 18,000 feet TVD SS,
(2) A sidetrack with a perforated interval the top of which is
15,000 to less than 18,000 feet TVD SS,
(3) An original well with a perforated interval the top of which is at
18,000 feet TVD SS,
(4) A sidetrack with a perforated interval the top of which is at
18,000 feet TVD SS,
from
15 BCF.
from
4 BCF plus 600 MCF times sidetrack measured depth (rounded to the
nearest 100 feet) but no more than 15 BCF.
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
least
least
4 BCF plus 600 MCF times sidetrack measured depth (rounded to the
nearest 100 feet) but no more than 25 BCF.
in this paragraph is in addition to any
RSV your lease already may have earned
from a qualified deep well with a
perforated interval whose top is from
15,000 feet to less than 18,000 feet TVD
SS.
If you have a qualified deep well or a qualified phase 1 ultra-deep well
that is . . .
Then you earn an RSV on this amount of gas production:
(1) An original well or a sidetrack with a 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 interval the top of which is 18,000
feet TVD SS or deeper,
(3) A sidetrack with a perforated interval the top of which is 18,000 feet
TVD SS or deeper,
0 BCF.
mstockstill on DSK4VPTVN1PROD with RULES2
(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 § 203.31 or § 203.41.
(e) The following examples illustrate
how this section applies, assuming your
lease meets the location, prior
production, and lease issuance
conditions in § 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 §§ 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
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10 BCF.
4 BCF plus 600 MCF times sidetrack measured depth (rounded to the
nearest 100 feet) but no more than 10 BCF.
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 §§ 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 §§ 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);
PO 00000
Frm 00043
Fmt 4701
Sfmt 4700
(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
§§ 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 §§ 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 §§ 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
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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
§ 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 § 203.31(b)
applies, would not earn any additional RSV
(as prescribed in § 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)]} 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 §§ 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.
§ 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 § 203.41.
If . . .
Then . . .
(a) Your lease has produced gas or oil from a well with a perforated interval the top of which is 18,000 feet TVD SS or deeper,
(b) You determine RSV under § 203.41 for the first qualified deep well
or qualified phase 1 ultra-deep well on your lease (whether an original well or a sidetrack) because you drilled and produced it within
the time intervals set forth in the definitions for qualified wells,
(c) A qualified deep well or qualified phase 1 ultra-deep well on your
lease is within a unitized portion of your lease,
your lease cannot earn an RSV under § 203.41 as a result of drilling
any subsequent deep wells or phase 1 ultra-deep wells.
that determination establishes the total RSV available for that drilling
depth interval on your lease (i.e., either 15,000–18,000 feet TVD SS,
or 18,000 feet TVD SS and deeper), regardless of the number of
subsequent qualified wells you drill to that depth interval.
the RSV earned by that well under § 203.41 applies only to production
from qualified wells on or allocated to your lease and not to other
leases within the unit.
the lease with the perforated interval that initially produces earns the
RSV. However, if the perforated interval crosses a lease line, the
lease where the surface of the well is located earns the RSV.
that RSV is in addition to any RSS for your lease under § 203.45 that
results from a different wellbore.
the RSV is not forfeited or terminated, but you may not apply the RSV
under § 203.41 to production from the non-qualified well.
you still owe minimum royalties or rentals in accordance with your
lease terms.
unused RSVs transfer to a successor lessee and expire with the lease.
(d) Your qualified deep well or qualified phase 1 ultra-deep well is a directional well (either an original well or a sidetrack) drilled across a
lease line,
(e) You earn an RSV under § 203.41,
(f) Your lease earns an RSV under § 203.41 and later produces from a
well that is not a qualified well,
(g) You qualify for an RSV under paragraphs (b) or (c) of § 203.41,
(h) You transfer your 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 § 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.
mstockstill on DSK4VPTVN1PROD with RULES2
§ 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 § 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 §§ 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 §§ 203.45 and 203.46 does
not count toward the lease RSV.
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(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 BSEEapproved unit. Subject to the price
conditions in § 203.48, you must apply
the RSV prescribed in § 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
§ 203.35 or § 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
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Frm 00044
Fmt 4701
Sfmt 4700
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 § 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 § 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 § 203.0). Only the first well
earns an RSV equal to 15 BCF (see § 203.41(a)
and (b)). You must apply any remaining RSV
each month beginning in October 2011 to
production from both qualified deep wells
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until the 15 BCF RSV is fully utilized
according to paragraph (b)(2) of this section.
mstockstill on DSK4VPTVN1PROD with RULES2
(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 § 203.48, you must apply
the RSV prescribed under § 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 § 203.35
or § 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
§ 203.35 or § 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 § 203.31
or § 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 § 203.41 to:
(1) Production from completions less
than 15,000 feet TVD SS, except in cases
where the qualified deep well is reperforated 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.
§ 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
64475
(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 ultradeep 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
§ 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 § 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 § 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.
§ 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 § 203.41.
(a) If you drill a certified unsuccessful
well and you satisfy the administrative
requirements of § 203.47, subject to the
price conditions in § 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 § 203.46.
If you have a certified unsuccessful well that is:—
Then your lease earns an RSS on this volume of oil and gas production as prescribed in this section and § 203.46:—
(1) An original well and your lease has not produced gas or oil from a
deep well or an ultra-deep well,
5 BCFE.
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If you have a certified unsuccessful well that is:—
Then your lease earns an RSS on this volume of oil and gas production as prescribed in this section and § 203.46:—
(2) A sidetrack (with a sidetrack measured depth of at least 10,000
feet) and your lease has not produced gas or oil from a deep well or
an ultra-deep well,
(3) An original well or a sidetrack (with a 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,
0.8 BCFE plus 120 MCFE times sidetrack measured depth (rounded to
the nearest 100 feet) but no more than 5 BCFE.
(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 § 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 §§ 203.31 through 203.33
and §§ 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.
mstockstill on DSK4VPTVN1PROD with RULES2
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
§ 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 § 203.45.
(c) The conversion from oil to gas for
using the royalty suspension
supplement is specified in § 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
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2 BCFE.
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.
§ 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
§§ 203.40, 203.43, 203.45, 203.47, and
203.48 you must apply an RSS in
§ 203.45 to the earliest oil and gas
production:
(1) Occurring on and after the day you
file the information under § 203.47(b),
(2) From, or allocated under a BSEEapproved unit agreement to, the lease on
which the certified unsuccessful well
was drilled, without regard to the
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drilling depth of the well producing the
gas or oil.
(b) If you have a royalty suspension
volume for the lease under § 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 § 203.45, your RSS applies to the
earliest subsequent production of gas
and oil from, or allocated under a BSEEapproved 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 § 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
§ 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
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suspension supplement remaining at the
beginning of that month.
§ 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
§ 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
64477
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.
§ 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 §§ 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 water . . .
And issued . . .
The applicable threshold price is . . .
(1) Partly or entirely less than 200
meters deep,
(2) Partly or entirely less than 200
meters deep,
(3) Entirely more than 200 meters
and entirely less than 400 meters
deep,
before December 18, 2008,
$10.15 per MMBtu, adjusted annually after calendar year 2007 for inflation.
$4.55 per MMBtu, adjusted annually after calendar year 2007 for inflation unless the lease terms prescribe a different price threshold.
$4.55 per MMBtu, adjusted annually after calendar year 2007 for inflation unless the lease terms prescribe a different price threshold.
after December 18, 2008,
on any date,
(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 §§ 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.
§ 203.49 May I substitute the deep gas
drilling provisions in this part for the deep
gas royalty relief provided in my lease
terms?
mstockstill on DSK4VPTVN1PROD with RULES2
(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.
Royalty Relief for End-of-Life Leases
§ 203.50 Who may apply for end-of-life
royalty relief?
(a) You may exercise an option to
replace the applicable lease terms for
royalty relief related to deep-well
drilling with those in § 203.0 and
§§ 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.
You may apply for royalty relief in
two situations.
(a) Your end-of-life lease (as defined
in § 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 § 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
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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.
§ 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 § 203.83) and
(b) A net revenue and relief
justification report (specified in
§ 203.84).
§ 203.52
relief?
What criteria must I meet to get
(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 § 203.84).
(b) To re-qualify for relief, e.g., either
applying for additional relief on top of
relief already granted, or applying for
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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.
§ 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 § 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.
§ 203.54 How does my relief arrangement
for an oil and gas lease operate if prices
rise sharply?
mstockstill on DSK4VPTVN1PROD with RULES2
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.
§ 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
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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.
§ 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
§ 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 §§ 203.61(b) and 203.62 for an
individual lease, unit or project if you:
(a) Hold a pre-Act lease (as defined in
§ 203.0) that we have assigned to an
authorized field (as defined in § 203.0);
(b) Propose an expansion project (as
defined in § 203.0); or
(c) Propose a development project (as
defined in § 203.0).
§ 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 § 203.3.
(b) You must wait at least 90 days
after receiving our assessment to apply
for relief under § 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.
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§ 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.
§ 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 § 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
§ 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 § 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.
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§ 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 § 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.
§ 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
64479
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 § 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
costs,
Ask to extend the 120-day or 180-day evaluation period. The extension we request will equal the
number of days between when you receive our request for records and the day we receive the
records.
Add another 30 days. We may add more than 30 days, but only if you agree.
(2) We cannot evaluate your application
for a valid reason, such as missing
vital information or inconsistent or inconclusive supporting data,
(3) We need more data, explanations, or
revision,
Ask to extend the 120-day or 180-day evaluation period. The extension we request will equal the
number of days between when you receive our request and the day we receive the information.
(d) We may change your assumptions
under § 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.
§ 203.66 What happens if BSEE does not
act in the time allowed?
If we do not act within the timeframes
established under § 203.65, you get
royalty relief according to the following
table.
If you apply for royalty relief for
And we do not decide within the time specified,
As long as you
(a) An authorized field,
(b) An expansion project,
(c) A development project,
You get the minimum suspension volumes specified in § 203.69,
You get a royalty suspension for the first year of production,
You get a royalty suspension for initial production for the number of
months that a decision is delayed beyond the stipulated timeframes
set by § 203.65, plus all the royalty suspension volume for which
you qualify,
Abide by §§ 203.70 and 203.76.
Abide by §§ 203.70 and 203.76.
Abide by §§ 203.70 and 203.76.
§ 203.67 What economic criteria must I
meet to get royalty relief on an authorized
field or project?
uneconomic while you are paying
royalties and must become economic
with royalty relief.
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
§ 203.68 What pre-application costs will
BSEE consider in determining economic
viability?
determining economic viability for
purposes of royalty relief.
(b) We will consider sunk costs
according to the following table.
(a) We will not consider ineligible
costs as set forth in § 203.89(h) in
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.
Whether an authorized field, a development project, or an expansion project can become economic with full relief (see § 203.67).
How much suspension volume is necessary to make the field, a development project, or an
expansion project economic (see § 203.69(c)).
Whether a development project or an expansion project needs relief to become economic.
(2) Not include sunk costs,
mstockstill on DSK4VPTVN1PROD with RULES2
(3) Not include sunk costs,
(4) Include sunk costs for the project discovery
well on each lease,
§ 203.69 If my application is approved,
what royalty relief will I receive?
If we approve your application,
subject to certain conditions, we will
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not collect royalties on a specified
suspension volume for your field,
development project, or expansion
project. Suspension volumes include
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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
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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 §§ 203.40
through 203.49 or ultra-deep gas royalty
relief under §§ 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
offshore Alaska,
A volume equal to the combined royalty suspension volumes (or the
volume equivalent based on the data in your approved application
for other forms of royalty suspension) with which BSEE issued the
leases participating in the application that have or plan a well into
a reservoir identified in the application,
10 percent of the median of the
distribution of known recoverable resources upon which
BSEE based approval of your
application from all reservoirs
included in the project.
(2) Leases offshore Alaska or other
deep water GOM leases issued in
sales after November 28, 2000,
A volume equal to 10 percent of the median of the distribution of
known recoverable resources upon which BSEE based approval of
your application from all reservoirs included in the project.
(f) If your application includes preAct 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
§ 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.
§ 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 confirmation report.
Within 18 months after approval of relief.
(b) Post-production report.
Within 120 days after the start of production
that is subject to the approved royalty suspension volume.
BSEE Director may grant you an extension
under § 203.79(c) for up to 6 months.
With acceptable justification from you, the
BSEE Regional Director for your region
may extend the due date up to 30 days.
§ 203.71 How does BSEE allocate a field’s
suspension volume between my lease and
other leases on my field?
mstockstill on DSK4VPTVN1PROD with RULES2
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 §§ 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
your authorized field after we approve relief,
We will not change your authorized field’s royalty
suspension volume determined under § 203.69,
Production from the assigned eligible lease(s)
counts toward the 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.
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64481
Then . . .
And . . .
(2) We assign a pre-Act or post-November 2000 deep water lease to
your field after we approve your
application,
We will not change your field’s royalty suspension
volume,
(3) We assign another lease that
you operate to your field while we
are evaluating your application,
In our evaluation of your authorized field, we will
take into account the value of any royalty relief
the added lease already has under 30 CFR
560.114 or its lease document. If we find your
authorized field still needs additional royalty suspension volume, that volume will be at least the
combined royalty suspension volume to which all
added leases on the field are entitled, or the minimum suspension volume of the authorized field,
whichever is greater,
(4) We assign another operator’s
lease to your field while we are
evaluating your application,
We will change your field’s minimum suspension
volume provided the assigned lease joins the application and is entitled to a larger minimum suspension volume,
(5) We reassign a well on a pre-Act,
eligible, or royalty suspension
lease from field A to field B,
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If . . .
The past production from the well counts toward
the royalty suspension volume that we grant
under § 203.69 to field B,
The assigned lease(s) may share in any remaining
royalty relief by filing the short-form application
specified in § 203.83 and authorized in § 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.
(i) You toll the time period for evaluation until you
modify your application to be consistent with the
newly constituted field;
(ii) We have an additional 60 days to review the
new information; and
(iii) The assigned pre-Act lease or royalty suspension lease shares the royalty suspension we
grant to the newly constituted field. An eligible
lease does not share the royalty suspension we
grant to the new field. If you do not agree to toll,
we will have to reject your application due to incomplete information. Production from an assigned eligible lease counts toward the royalty
suspension volume that we grant under § 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.
(i) You both toll the time period for evaluation until
both of you modify your application to be consistent with the new field;
(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
§ 203.83 and authorized in § 203.82.
For any field based relief, the past production for
that well will not count toward any royalty suspension volume that we grant under § 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 royaltysuspension 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.
§ 203.72 Can my lease receive more than
one suspension volume?
Yes. You may apply for royalty relief
that involves more than one suspension
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volume under § 203.62 in two
circumstances.
(a) Each field that includes your lease
may receive a separate royaltysuspension volume, if it meets the
evaluation criteria of § 203.67.
(b) An expansion project on your
lease may receive a separate royaltysuspension 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 § 203.67.
§ 203.73 How do suspension volumes
apply to natural gas?
You must measure natural gas
production under the royaltysuspension volume as follows: 5.62
thousand cubic feet of natural gas,
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measured in accordance with 30 CFR
part 250, subpart L, equals one barrel of
oil equivalent.
§ 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
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Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations
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 §§ 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.
§ 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 § 203.62.
We will evaluate your application under
§ 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.
§ 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 § 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 postproduction development report
(§ 203.70). Development costs are those
expenditures defined in § 203.89(b)
incurred between the application
submission date and start of production.
If you report this fact in the postproduction 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 royaltysuspension volume after you qualified
for a redetermination under § 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
§ 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 postproduction 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.
§ 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.
§ 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
§§ 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.
mstockstill on DSK4VPTVN1PROD with RULES2
For . . .
The base price threshold is . . .
(1) Pre-Act leases in the GOM,
(2) Post-November 2000 deep water leases in the GOM or leases offshore of Alaska for which the lease or Notice of Sale set a base
price threshold,
(3) Post-November 2000 deep water leases in the GOM or leases offshore of Alaska for which the lease or Notice of Sale did not set a
base price threshold,
set by statute.
indicated in your original lease agreement or, if none, those in the Notice of Sale under which your lease was issued.
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the threshold set by statute for pre-Act leases.
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(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 § 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.
§ 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
§ 203.67 and the royalty-suspension
volumes under § 203.69 are final agency
actions.
(c) If you cannot start construction by
the deadline in § 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.
§ 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
64483
summarized in § 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
§ 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
lease
Required reports
(1) Administrative information Report ..............................................................
(2) Net revenue & relief justification report ......................................................
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X
X
Expansion
project
Pre-act lease
Development
project
X
........................
X
........................
X
........................
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Deep water
End-of-life
lease
Required reports
(3) Economic viability & relief justification report (RSVP model inputs justified by other required reports) .....................................................................
(4) G&G report .................................................................................................
(5) Engineering report ......................................................................................
(6) Production report ........................................................................................
(7) Deep water cost report ..............................................................................
(8) Fabricator’s confirmation report .................................................................
(9) Post-production development report ..........................................................
(b) You must certify that all
information in your application,
fabricator’s confirmation and postproduction 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 postproduction 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.
mstockstill on DSK4VPTVN1PROD with RULES2
§ 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
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........................
........................
........................
........................
........................
........................
........................
(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 § 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.
§ 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);
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Expansion
project
Pre-act lease
Development
project
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
(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).
§ 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;
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(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.
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§ 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 (§§ 203.86 through
203.89) and
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(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.
§ 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-ofthe-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-ofthe-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:
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64485
(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
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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.
§ 203.87
What is in an engineering report?
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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
(§ 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.
§ 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
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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.
§ 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 fielddevelopment scenarios and production
profiles (conservative, most likely,
optimistic). You should express costs in
constant real dollar terms for the base
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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).
§ 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.
§ 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 preproduction 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
§ 203.81(c).
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Subpart C—Federal and Indian Oil
[Reserved]
Fees
Subpart D—Federal and Indian Gas
[Reserved]
Inspection of Operations
250.125
250.126
Service fees.
Electronic payment instructions.
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?
Subpart E—Solid Minerals, General
[Reserved]
Subpart F—[Reserved]
Subpart G—Other Solid Minerals
[Reserved]
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?
Subpart H—Geothermal Resources
[Reserved]
Subpart I—OCS Sulfur [Reserved]
Special Types of Approvals
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.
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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?
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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?
64487
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.
Naming and Identifying Facilities and Wells
(Does Not Include MODUs)
Subpart B—Plans and Information
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]
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?
Suspensions
Post-Approval Requirements for the EP,
DPP, and DOCD
250.282 Do I have to conduct post-approval
monitoring?
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
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?
250.180 What am I required to do to keep
my lease term in effect?
250.181–250.185 [Reserved]
Subpart C—Pollution Prevention and
Control
250.300 Pollution prevention.
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250.301
Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations
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?
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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?
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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 wellcontrol 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.
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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 wellcompletion 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 wellworkover 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?
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250.618
250.619
Tubing and wellhead equipment.
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?
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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?
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250.921 How do I analyze my platform for
cumulative fatigue?
Subpart J—Pipelines and Pipeline Rightsof-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-ofway 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-ofway grants.
250.1019 Relinquishment of pipeline rightof-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?
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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?
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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 BOEMspecified surety instrument meet?
250.1491 How will BOEM determine the
amount of my bond or other surety
instrument?
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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?
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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 wellworkover requirements.
250.1621 Crew instructions.
250.1622 Approvals and reporting of wellcompletion 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?
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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.
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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
§ 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
64491
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.
§ 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,
(2) Development and Production Plans (DPP),
(3) Downhole commingling,
(4) Exploration Plans (EP),
(5) Flaring,
(6) Gas measurement,
(7) Off-lease geological and geophysical permits,
(8) Oil spill financial responsibility coverage,
(9) Oil and gas production safety systems,
(10) Oil spill response plans,
(11) Oil and gas well-completion operations,
(12) Oil and gas well-workover operations,
(13) Decommissioning Activities,
(14) Platforms and structures,
(15) Pipelines and Pipeline Rights-of-Way,
(16) Sulphur operations,
(17) Training,
(18) Unitization,
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
CFR 250, subpart D.
CFR 550, subpart B.
CFR 250, subpart K.
CFR, 550, subpart B.
CFR 250, subpart K.
CFR 250, subpart L.
CFR 551.
CFR 553.
CFR 250, subpart H.
CFR 254.
CFR 250, subpart E.
CFR 250, subpart F.
CFR 250, subpart Q.
CFR 250, subpart I.
CFR 250, subpart J and 30 CFR 550, subpart J.
CFR 250, subpart P.
CFR 250, subpart O.
CFR 250, subpart M.
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§ 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?
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.
§ 250.105
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To appeal orders or decisions issued
under BSEE regulations in 30 CFR parts
250 to 282, follow the procedures in 30
CFR part 290.
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.).
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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
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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
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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,
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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,
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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 § 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 columnstabilized-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 skidoff drilling units) or other vessels
engaged in drilling or downhole
operations. They are used for
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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 § 250.490(b), means a
vessel, a structure, or an artificial island
used for drilling, well completion, wellworkover, or production operations.
(4) As used in §§ 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
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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, 3dimensional 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, 3dimensional 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 BOEMapproved 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.,
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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.
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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.
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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 pumpthrough-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;
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(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
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§ 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.
§ 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:
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(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.
§ 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 § 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 § 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.
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§ 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.
§ 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 § 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 safewelding areas.
(d) How you will prevent sparkproducing activities (i.e., grinding,
abrasive blasting/cutting and arcwelding) in hazardous locations.
§ 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.
§ 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.
§ 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
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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.
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§ 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 § 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 § 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 § 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.
§§ 250.115–250.117
[Reserved]
§ 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.
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§ 250.119
[Reserved]
§ 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
§ 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 offunit location, you must pay royalties
when the gas is first produced.
§ 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.
§ 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.
§ 250.123
[Reserved]
§ 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
§ 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.
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Service—processing of the following:
Fee amount
(1) [Reserved]
(2) [Reserved]
(3) Suspension of Operations/Suspension of Production (SOO/SOP)
Request.
(4) [Reserved]
(5) [Reserved]
(6) Deepwater Operations Plan ..............................................................
(7) [Reserved]
(8) Application for Permit to Drill (APD; Form BSEE–0123) ..................
30 CFR citation
$1,968 ............................................
§ 250.171(e).
$3,336 ............................................
§ 250.292(p).
$1,959 for initial applications only;
no fee for revisions.
§ 250.410(d);
§ 250.513(b);
§ 250.515;
§ 250.1605;
§ 250.1617(a); § 250.1622.
§ 250.460;
§ 250.513(b);
§ 250.613(b);
250.1618(a);
§ 250.1622; § 250.1704(g).
§ 250.802(e).
(9) Application for Permit to Modify (APM; Form BSEE–0124) ..............
$116 ...............................................
(10) New Facility Production Safety System Application for facility with
more than 125 components.
$5,030 A component is a piece of
equipment or ancillary system
that is protected by one or more
of the safety devices required by
API RP 14C (as incorporated by
reference in § 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.
$1,218 Additional fee of $8,313
will be charged if BSEE deems
it necessary to visit a facility offshore, and $4,766 to visit a facility in a shipyard.
$604 ...............................................
(11) New Facility Production Safety System Application for facility with
25–125 components.
(31) Simple Surface Commingling and Measurement Application .........
$1,271 ............................................
(32)
(33)
(34)
(35)
(36)
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(12) New Facility Production Safety System Application for facility with
fewer than 25 components.
(13) Production Safety System Application—Modification with more
than 125 components reviewed.
(14) Production Safety System Application—Modification with 25–125
components reviewed.
(15) Production Safety System Application—Modification with fewer
than 25 components reviewed.
(16) Platform Application—Installation—Under the Platform Verification
Program.
(17) Platform Application—Installation—Fixed Structure Under the
Platform Approval Program.
(18) Platform Application—Installation—Caisson/Well Protector ............
(19) Platform Application—Modification/Repair ......................................
(20) New Pipeline Application (Lease Term) ..........................................
(21) Pipeline Application—Modification (Lease Term) ............................
(22) Pipeline Application—Modification (ROW) ......................................
(23) Pipeline Repair Notification .............................................................
(24) Pipeline Right-of-Way (ROW) Grant Application .............................
(25) Pipeline Conversion of Lease Term to ROW ..................................
(26) Pipeline ROW Assignment ..............................................................
(27) 500 Feet From Lease/Unit Line Production Request ......................
(28) Gas Cap Production Request ..........................................................
(29) Downhole Commingling Request ....................................................
(30) Complex Surface Commingling and Measurement Application ......
$11,698 ..........................................
$831 ...............................................
$4,342 ............................................
$1,059 ............................................
$2,012 ............................................
Voluntary Unitization Proposal or Unit Expansion ..........................
Unitization Revision .........................................................................
Application to Remove a Platform or Other Facility ........................
Application to Decommission a Pipeline (Lease Term) ..................
Application to Decommission a Pipeline (ROW) .............................
(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
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§ 250.802(e).
§ 250.802(e).
$561 ...............................................
§ 250.802(e).
$201 ...............................................
§ 250.802(e).
$85 .................................................
§ 250.802(e).
$21,075 ..........................................
§ 250.905(l).
$3,018 ............................................
§ 250.905(l).
$1,536 ............................................
$3,601 ............................................
$3,283 ............................................
$1,906 ............................................
$3,865 ............................................
$360 ...............................................
$2,569 ............................................
$219 ...............................................
$186 ...............................................
$3,608 ............................................
$4,592 ............................................
$5,357 ............................................
$3,760 ............................................
§ 250.905(l)
§ 250.905(l).
§ 250.1000(b).
§ 250.1000(b).
§ 250.1000(b).
§ 250.1008(e).
§ 250.1015(a).
§ 250.1015(a).
§ 250.1018(b).
§ 250.1156(a).
§ 250.1157.
§ 250.1158(a).
§ 250.1202(a);
§ 250.1203(b);
§ 250.1204(a).
§ 250.1202(a);
§ 250.1203(b);
§ 250.1204(a).
§ 250.1303(d).
§ 250.1303(d).
§ 250.1727.
§ 250.1751(a) or § 250.1752(a).
§ 250.1751(a) or § 250.1752(a).
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
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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.
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§ 250.126
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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: https://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
§ 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.
§ 250.131 Will BSEE notify me before
conducting an inspection?
BSEE conducts both scheduled and
unscheduled inspections.
§ 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-ofway; 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.
send us your reimbursement request
within 90 days of the inspection.
Disqualification
§ 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.
§ 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
§ 250.133 Will BSEE reimburse me for my
expenses related to inspections?
§ 250.140 When will I receive an oral
approval?
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
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 orally
Give you an oral approval,
(b) Request approval in writing,
Give you an oral approval if quick
action is needed,
Give you an oral approval,
You must then confirm the oral request by sending us a written request within 72 hours.
We will send you a written approval afterward. It will include any conditions that we place on the oral approval.
You don’t have to follow up with a written request unless the Regional Supervisor requires it. When you stop the approved flaring,
you must promptly send a letter summarizing the location, dates
and hours, and volumes of liquid hydrocarbons produced and gas
flared by the approved flaring (see 30 CFR 250, subpart K).
(c) Request approval orally for gas
flaring,
mstockstill on DSK4VPTVN1PROD with RULES2
§ 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.
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(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.
§ 250.142 How do I receive approval for
departures?
We may approve departures to the
operating requirements. You may apply
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for a departure by writing to the District
Manager or Regional Supervisor.
§ 250.143
[Reserved]
§ 250.144
[Reserved]
§ 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
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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.
§ 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)
mstockstill on DSK4VPTVN1PROD with RULES2
§ 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.
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(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.
§ 250.151 How do I name facilities in the
Pacific Region?
The operator assigns a name to the
facility.
§ 250.152 How do I name facilities in the
Alaska Region?
Facilities will be named and
identified according to the Regional
Director’s directions.
§ 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.
§ 250.154
display?
What identification signs must I
(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 3inch 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
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64499
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.
§ 250.160–250.167
[Reserved]
Suspensions
§ 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).
§ 250.169 What effect does suspension
have on my lease?
(a) A suspension may extend the term
of a lease (see § 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
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(2) A willful violation of a provision
of the lease or governing statutes and
regulations.
§ 250.170
last?
How long does a suspension
(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.
§ 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 § 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 § 250.125
of this subpart.
mstockstill on DSK4VPTVN1PROD with RULES2
§ 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
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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
§ 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.
§ 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.
§ 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).
§ 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:
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Sfmt 4700
(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 hydrocarbonbearing 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 hydrocarbonbearing 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
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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.
§ 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.
§ 250.177 What additional requirements
may the Regional Supervisor order for a
suspension?
mstockstill on DSK4VPTVN1PROD with RULES2
If BSEE grants or directs a suspension
under paragraph § 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
§ 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
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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 §§ 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 § 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
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64501
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.
§§ 250.181–250.185
[Reserved]
Information and Reporting
Requirements
§ 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 § 250.197
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or otherwise exempt from public
disclosure under law or regulation.
§ 250.187 What are BSEE’s incident
reporting requirements?
(a) You must report all incidents
listed in § 250.188(a) and (b) to the
District Manager. The specific reporting
requirements for these incidents are
contained in §§ 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.
mstockstill on DSK4VPTVN1PROD with RULES2
§ 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
§ 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
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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.
§ 250.189 Reporting requirements for
incidents requiring immediate notification.
For an incident requiring immediate
notification under § 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.
§ 250.190 Reporting requirements for
incidents requiring written notification.
(a) For any incident covered under
§ 250.188, you must submit a written
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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.
§ 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
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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.
mstockstill on DSK4VPTVN1PROD with RULES2
§ 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 email (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
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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.
§ 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.
§ 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.
§ 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.
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64503
§ 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.
§ 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:
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On form . . .
Data and information not immediately available are . . .
Excepted data will be made available . . .
(1) BSEE–0123, Application for Permit to Drill,
Items 15, 16, 22 through 25,
(2) BSEE–0123S, Supplemental APD Information Sheet,
Items 3, 7, 8, 15 and 17,
(3) BSEE–0124, Application for Permit to Modify,
Item 17,
(4) BSEE–0125, End of Operations Report,
Items 12, 13, 17, 21, 22, 26 through 38,
(5) BSEE–0126, Well Potential Test Report,
(6) [Reserved]
(7) BSEE–0133 Well Activity Report,
Item 101,
When the well goes on production or according to the table in paragraph (b) of this section, whichever is earlier.
When the well goes on production or according to the table in paragraph (b) of this section, whichever is earlier.
When the well goes on production or according to the table in paragraph (b) of this section, whichever is earlier.
When the well goes on production or 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.
2 years after you submit it.
(8) BSEE–0133S Open Hole Data Report,
Item 10 Fields [WELLBORE START DATE,
TD DATE, OP STATUS, END DATE, MD,
TVD, AND MW PPG]. Item 11 Fields
[WELLBORE START DATE, TD DATE,
PLUGBACK DATE, FINAL MD, AND FINAL
TVD] and Items 12 through 15,
Boxes 7 and 8,
When the well goes on production or according to the table in paragraph (b) of this section, whichever is earlier.
When the well goes 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:
If . . .
BSEE will release . . .
At this time . . .
Special provisions . . .
(1) The Director determines that
data and information are needed
for specific scientific or research
purposes for the Government,
Geophysical data, Geological data
Interpreted G&G information,
Processed G&G information,
Analyzed geological information,
Geophysical data, Geological
data, Interpreted G&G information, Processed geological information, Analyzed geological information,
At any time,
Geophysical data, Geological
data, Processed G&G information Interpreted G&G information, Analyzed geological information,
When your lease terminates,
BSEE will release data and information only if release would further the National interest without unduly damaging the competitive position of the lessee.
BSEE will release the data and
information earlier than 60 days
if the Regional Supervisor determines it is needed by affected States to make decisions
under 30 CFR 550, subpart B.
The Regional Supervisor will reconsider earlier release if you
satisfy him/her that it would unduly damage your competitive
position.
This release time applies only if
the provisions in this table governing high-resolution systems
and 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.
(2) Data or information is collected
with high-resolution systems
(e.g.,
bathymetry,
side-scan
sonar, subbottom profiler, and
magnetometer) to comply with
safety or environmental protection requirements,
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(3) Your lease is no longer in effect,
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60 days after BSEE receives the
data or information, if the Regional Supervisor deems it necessary,
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64505
If . . .
BSEE will release . . .
At this time . . .
Special provisions . . .
(4) Your lease is still in effect,
Geophysical data, Processed
geophysical information, Interpreted G&G information,
10 years after you submit the
data and information,
(5) Your lease is still in effect and
within the primary term specified
in the lease,
Geological data, Analyzed geological information,
2 years after the required submittal date or 60 days after a
lease sale if any portion of an
offered lease is within 50 miles
of a well, whichever is later,
(6) Your lease is in effect and beyond the primary term specified
in the lease,
(7) Data or information is submitted on well operations,
Geological data, Analyzed geological information,
2 years after the required submittal date,
This release time applies only if
the provisions in this table 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.
These release times apply only if
the provisions in this table governing high-resolution systems
and the provisions in 30 CFR
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.
None.
Descriptions of downhole locations, operations, and equipment,
(8) Data and information are obtained from 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 high-resolution data
and information released under
paragraph (b)(2) of this section
data and information acquired by
a permit under 30 CFR part 551
are submitted by a lessee under
30 CFR part 203, 30 CFR part
250, or 30 CFR part 550,
Any data or information obtained,
When the well goes on production
or when geological data is released
according
to
§§ 250.197(b)(5) and (b)(6),
whichever occurs earlier,
At any time,
G&G data, analyzed geological information, processed and interpreted G&G information,
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(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
§ 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)
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Geological data and information:
10 years after BOEM issues the
permit; Geophysical data: 50
years after BOEM issues the
permit; Geophysical information: 25 years after BOEM
issues the permit,
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
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Directional survey data may be
released earlier to the owner of
an adjacent lease according to
Subpart D of this part.
None.
None.
(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
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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 §§ 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:
https://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: https://
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 § 250.901.
(2) ACI 318R–95, Commentary on
Building Code Requirements for
Reinforced Concrete, incorporated by
reference at § 250.901.
(3) ACI 357R–84, Guide for the Design
and Construction of Fixed Offshore
Concrete Structures, 1984; reapproved
1997, incorporated by reference at
§ 250.901.
(f) American Institute of Steel
Construction, Inc. (AISC), AISC
Standards, One East Wacker Drive, Suite
700, Chicago, IL 60601–1802; https://
www.aisc.org; phone: 312–670–2400:
(1) ANSI/AISC 360–05, Specification
for Structural Steel Buildings
incorporated by reference at § 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;
https://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; https://www.asme.org;
phone: 973–882–5155:
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(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 § 250.803
and § 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 §§ 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
§§ 250.803 and 250.1629;
(4) ANSI/ASME B 16.5–2003, Pipe
Flanges and Flanged Fittings
incorporated by reference at § 250.1002;
(5) ANSI/ASME B 31.8–2003, Gas
Transmission and Distribution Piping
Systems incorporated by reference at
§ 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 § 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 § 250.806;
(8) ANSI Z88.2–1992, American
National Standard for Respiratory
Protection, incorporated by reference at,
§ 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; https://
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
§§ 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
§ 250.901;
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(3) API Bulletin 2INT–EX, Interim
Guidance for Assessment of Existing
Offshore Structures for Hurricane
Conditions, May 2007; incorporated by
reference at § 250.901;
(4) API Bulletin 2INT–MET, Interim
Guidance on Hurricane Conditions in
the Gulf of Mexico, May 2007;
incorporated by reference at § 250.901;
(5) API MPMS, Chapter 1—
Vocabulary, Second Edition, July 1994;
incorporated by reference at § 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 § 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 § 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 § 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
§ 250.1202;
(10) API MPMS, Chapter 4—Proving
Systems, Section 1—Introduction, Third
Edition, February 2005; incorporated by
reference at § 250.1202;
(11) API MPMS, Chapter 4—Proving
Systems, Section 2—Displacement
Provers, Third Edition, September 2003;
incorporated by reference at § 250.1202;
(12) API MPMS, Chapter 4—Proving
Systems, Section 4—Tank Provers,
Second Edition, May 1998, reaffirmed
November 2005; incorporated by
reference at § 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 § 250.1202;
(14) API MPMS, Chapter 4—Proving
Systems, Section 6—Pulse Interpolation,
Second Edition, May 1999; reaffirmed
2003; incorporated by reference at
§ 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 § 250.1202;
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(16) API MPMS, Chapter 5—Metering,
Section 1—General Considerations for
Measurement by Meters, Fourth Edition,
September 2005; incorporated by
reference at § 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 § 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 § 250.1202;
(19) API MPMS, Chapter 5—Metering,
Section 4—Accessory Equipment for
Liquid Meters, Fourth Edition,
September 2005; incorporated by
reference at § 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 § 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 § 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 § 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 § 250.1202;
(24) API MPMS, Chapter 7—
Temperature Determination, First
Edition, June 2001; reaffirmed, March
2007; incorporated by reference at
§ 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 § 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 § 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;
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incorporated by reference at
§ 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 § 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 § 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 § 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 § 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 § 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 § 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 °F, and Table 6A—
Generalized Crude Oils and JP–4
Correction of Volume to 60 °F Against
API Gravity at 60 °F, API Standard 2540,
First Edition, August 1980; reaffirmed
March 1997; incorporated by reference
at § 250.1202;
(35) API MPMS, Chapter 11.2.2—
Compressibility Factors for
Hydrocarbons: 0.350–0.637 Relative
Density (60 °F/60 °F) and ¥50 °F to 140
°F Metering Temperature, Second
Edition, October 1986; reaffirmed:
December 2007; incorporated by
reference at § 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;
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64507
reaffirmed, December 2002;
incorporated by reference at § 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
§ 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 § 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
§ 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
§ 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 § 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 § 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 § 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 § 250.1203;
(45) API MPMS, Chapter 20—Section
1—Allocation Measurement, First
Edition, September 1993; reaffirmed
October 2006; incorporated by reference
at § 250.1202;
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(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 § 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 §§ 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 § 250.108;
(49) API RP 2FPS, RP for Planning,
Designing, and Constructing Floating
Production Systems; First Edition,
March 2001; incorporated by reference
at § 250.901;
(50) API RP 2I, In-Service Inspection
of Mooring Hardware for Floating
Structures; Third Edition, April 2008;
incorporated by reference at § 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 §§ 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 §§ 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 § 250.901;
(54) API RP 2T, Recommended
Practice for Planning, Designing, and
Constructing Tension Leg Platforms,
Second Edition, August 1997;
incorporated by reference at § 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 §§ 250.801 and 250.804;
(56) API RP 14C, Recommended
Practice for Analysis, Design,
Installation, and Testing of Basic
Surface Safety Systems for Offshore
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Production Platforms, Seventh Edition,
March 2001, reaffirmed: March 2007;
incorporated by reference at §§ 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 §§ 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 §§ 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 §§ 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
§§ 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 §§ 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 §§ 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 §§ 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 § 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
§§ 250.114, 250.459, 250.802, 250.803,
250.1628, and 250.1629;
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(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
§§ 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 § 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 § 250.806;
(69) API Spec. 2C, Specification for
Offshore Pedestal Mounted Cranes,
Sixth Edition, March 2004, Effective
Date: September 2004; incorporated by
reference at § 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 §§ 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 § 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 § 250.1002;
(73) ANSI/API Spec. 14A,
Specification for Subsurface Safety
Valve Equipment, Eleventh Edition,
October 2005, Effective Date: May 1,
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2006; also available as ISO 10432:2004;
incorporated by reference at § 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 §§ 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
§ 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
§ 250.1202;
(77) API Standard 2555, Method for
Liquid Calibration of Tanks, First
Edition, September 1966; reaffirmed
March 2002; incorporated by reference
at § 250.1202.
(78) API RP 90, Annular Casing
Pressure Management for Offshore
Wells, First Edition, August 2006,
incorporated by reference at § 250.518.
(79) API RP 65–Part 2, Isolating
Potential Flow Zones During Well
Construction; First Edition, May 2010;
incorporated by reference at § 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
§§ 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;
https://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 § 250.901;
(2) ASTM Standard C 94/C 94M–07,
approved January 1, 2007, Standard
Specification for Ready-Mixed Concrete;
incorporated by reference at § 250.901;
(3) ASTM Standard C 150–07,
approved May 1, 2007, Standard
Specification for Portland Cement;
incorporated by reference at § 250.901;
(4) ASTM Standard C 330–05,
approved December 15, 2005, Standard
Specification for Lightweight Aggregates
for Structural Concrete; incorporated by
reference at § 250.901;
(5) ASTM Standard C 595–08,
approved January 1, 2008, Standard
Specification for Blended Hydraulic
Cements; incorporated by reference at
§ 250.901;
(j) American Welding Society (AWS),
AWS Codes, 550 NW, LeJeune Road,
Miami, FL 33126; https://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 § 250.901;
(2) AWS D1.4–98, Structural Welding
Code—Reinforcing Steel, 1998 Edition;
incorporated by reference at § 250.901;
(3) AWS D3.6M:1999, Specification
for Underwater Welding (1999);
incorporated by reference at § 250.901.
(k) National Association of Corrosion
Engineers (NACE), NACE Standards,
1440 South Creek Drive, Houston, TX
77084; https://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
§§ 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 § 250.901.
64509
§ 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 § 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:
Reasons for collecting information and how used
(1) Subpart A, General (1010–0114), including Forms BSEE–0132,
Evacuation Statistics; BSEE–0143, Facility/Equipment Damage Report; BSEE–1832, Notification of Incidents of Noncompliance.
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30 CFR subpart, title and/or BSEE Form
(OMB Control No.)
To inform BSEE 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 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.
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30 CFR subpart, title and/or BSEE Form
(OMB Control No.)
Reasons for collecting information and how used
(2) Subpart B, Exploration and Development and Production Plans
(1010–0151).
To inform BSEE, States, and the public of planned exploration, 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.
To inform BSEE of measures to be taken to prevent water pollution. To
ensure that appropriate measures are taken to prevent water pollution.
To inform BSEE of the equipment and procedures to be used in drilling
operations on the OCS. To ensure that drilling operations are safe
and protect the human, marine, and coastal environment.
(3) Subpart C, Pollution Prevention and Control (1010–0057) ................
(4) Subpart D, Oil and Gas and Drilling Operations (1010–0141), including Forms BSEE–0123, Application for Permit to Drill; BSEE–
0123S, Supplemental APD Information Sheet; BSEE–0124, Application for Permit to Modify; BSEE–0125, End of Operations 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-Completion Operations (1010–0067) ..
(6) Subpart F, Oil and Gas Well Workover Operations (1010–0043) .....
(7) Subpart H, Oil and Gas Production Safety Systems (1010–0059) ....
(8) Subpart I, Platforms and Structures (1010–0149) ..............................
(9) Subpart J, Pipelines and Pipeline Rights-of-Way (1010–0050), including Form BSEE–0149, Assignment of Federal OCS Pipeline
Right-of-Way Grant.
(10) Subpart K, Oil and Gas Production Rates (1010–0041), including
Forms BSEE–0126, Well Potential Test Report and BSEE–0128,
Semiannual Well Test Report.
(11) Subpart L, Oil and Gas Production Measurement, Surface Commingling, and Security (1010–0051).
(12) Subpart M, Unitization (1010–0068) .................................................
(13) Subpart N, Remedies and Penalties ................................................
(14) Subpart O, Well Control and Production Safety Training (1010–
0128).
(15) Subpart P, Sulphur Operations (1010–0086) ...................................
(16) Subpart Q, Decommissioning Activities (1010–0142) ......................
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(17) Subpart S, Safety and Environmental Management Systems
(1010–0186), including Form BSEE–0131, Performance Measures
Data.
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To inform BSEE of the equipment and procedures to be used in wellcompletion operations on the OCS. To ensure that well-completion
operations are safe and protect the human, marine, and coastal environment.
To inform BSEE of the equipment 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.
To inform BSEE of the equipment 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.
To provide BSEE with information regarding the design, fabrication,
and installation of platforms on the OCS. To ensure the structural integrity of platforms installed on the OCS.
To provide BSEE with information regarding the design, installation,
and operation of pipelines on the OCS. To ensure that pipeline operations are safe and protect the human, marine, and coastal environment.
To inform BSEE of production rates for hydrocarbons produced on the
OCS. To ensure economic maximization of ultimate hydrocarbon recovery
To inform BSEE of the measurement of production, 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.
To inform BSEE of the unitization of leases. To ensure that unitization
prevents waste, conserves natural resources, and protects correlative rights.
The requirements in subpart N are exempt from the Paperwork Reduction Act of 1995 according to 5 CFR 1320.4.
To inform BSEE of training 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.
To inform BSEE of sulphur 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.
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.
The SEMS program will describe management commitment to safety
and the environment, as 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.
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Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations
Subpart B—Plans and Information
General Information
§ 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
You must submit a(n) . . .
(1)
(2)
(3)
(4)
64511
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)).
§ 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.
Before you . . .
[Reserved]
[Reserved]
[Reserved]
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 nonconventional production or completion technology.
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(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
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reference information and data
discussed in other plans or documents
you previously submitted or that are
otherwise readily available to BSEE.
§ 250.202
[Reserved]
§ 250.203
[Reserved]
§ 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
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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.
§ 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.
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Post-Approval Requirements for the EP,
DPP, and DOCD
§ 250.282 Do I have to conduct postapproval 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.
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.
§ 250.289
contain?
What must the Conceptual Plan
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.
Deepwater Operations Plan (DWOP)
§ 250.290 What operations require
approval of the Conceptual Plan?
§ 250.286
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.
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
§ 250.292 prescribes what the DWOP
must contain.
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§ 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.
§ 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
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§ 250.291
DWOP?
When and how must I submit the
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.
§ 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
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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 § 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 § 250.125.
§ 250.293 What operations require
approval of the DWOP?
You may not begin production until
BSEE approves your DWOP.
§ 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.
§ 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
§ 250.300
Pollution prevention.
(a) During the exploration,
development, production, and
transportation of oil and gas or sulphur,
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Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations
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
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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, treatedproduced 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.
§ 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.
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64513
Subpart D—Oil and Gas Drilling
Operations
General Requirements
§ 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.
§ 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.
§ 250.402
well?
When and how must I secure a
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 wellcontrol 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.
§ 250.403 What drilling unit movements
must I report?
(a) You must report the movement of
all drilling units on and off drilling
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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.
§ 250.404 What are the requirements for
the crown block?
§ 250.407 What tests must I conduct to
determine reservoir characteristics?
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 drillline slipping operation and record the
results of this operational check in the
driller’s report.
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.
§ 250.405 What are the safety
requirements for diesel engines used on a
drilling rig?
mstockstill on DSK4VPTVN1PROD with RULES2
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.
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 § 250.414(h)).
Procedures for obtaining approval are
described in § 250.141 of this part.
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.
§ 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
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§ 250.408 May I use alternative procedures
or equipment during drilling operations?
§ 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
§ 250.414(h)).
Applying for a Permit To Drill
§ 250.410
a well?
How do I obtain approval to drill
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 §§ 250.411 through 250.418;
(b) Include the well in your approved
Exploration Plan (EP), Development and
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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
§ 250.186; and
(3) Payment of the service fee listed in
§ 250.125.
§ 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
(a) Plat that shows locations
of the proposed well.
(b) Design criteria used for the
proposed well.
(c) Drilling prognosis ...............
(d) Casing and cementing programs.
(e) Diverter and BOP systems
descriptions.
(f) Requirements for using an
MODU.
(g) Additional information ........
Where to find
a description
§ 250.412
§ 250.413
§ 250.414
§ 250.415
§ 250.416
§ 250.417
§ 250.418
§ 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.
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§ 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.
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§ 250.414
include?
What must my drilling prognosis
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 § 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
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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 § 250.460 for safety
requirements).
§ 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 § 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
§ 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).
§ 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;
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(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 blindshear 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 APIlicensed 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
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submitted to BSEE. Prior to any shearing
ram tests or inspections, you must
notify the District Manager at least 24
hours in advance.
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§ 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 §§ 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,
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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.
§ 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 § 250.490), if applicable, and
not previously submitted;
(e) A welding plan (see §§ 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
§ 250.420(a)(6);
(i) Description of qualifications
required by § 250.416(f) of any
independent third party; and
(j) Such other information as the
District Manager may require.
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Casing and Cementing Requirements
§ 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 §§ 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.
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§ 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,
64517
intermediate, and production casings
(including liners). The District Manager
may approve or prescribe other casing
and cementing requirements where
appropriate.
Casing type
Casing requirements
Cementing requirements
(a) Drive or Structural ..........
Set by driving, jetting, or drilling to the minimum depth
as approved or prescribed by the District Manager.
(b) Conductor .......................
Design casing and select setting depths based on relevant engineering and geologic factors. These factors include the presence or absence of hydrocarbons, potential hazards, and water depths;
Set casing immediately before drilling into formations
known to contain oil or gas. If you encounter oil or
gas or unexpected formation pressure before the
planned casing point, you must set casing immediately.
Design casing and select setting depths based on relevant engineering and geologic factors. These factors include the presence or absence of hydrocarbons, potential hazards, and water depths.
If you drilled a portion of this hole, you must use
enough cement to fill the annular space back to the
mudline.
Use enough cement to fill the calculated annular space
back to the mudline.
Verify annular fill by observing cement returns. If you
cannot observe cement returns, use additional cement to ensure fill-back to the mudline.
For drilling on an artificial island or when using a glory
hole, you must discuss the cement fill level with the
District Manager.
(c) Surface ...........................
(d) Intermediate ....................
Design casing and select setting depth based on anticipated or encountered geologic characteristics or
wellbore conditions.
(e) Production ......................
Design casing and select setting depth based on anticipated or encountered geologic characteristics or
wellbore conditions.
(f) Liners ...............................
If you use a liner as conductor or surface casing, you
must set the top of the liner at least 200 feet above
the previous casing/liner shoe.
If you use a liner as an intermediate string below a surface string or production casing below an intermediate string, you must set the top of the liner at
least 100 feet above the previous casing shoe.
§ 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.
Use enough cement to fill the calculated annular space
to at least 200 feet inside the conductor casing.
When geologic conditions such as near-surface fractures and faulting exist, you must use enough cement to fill the calculated annular space to the
mudline.
Use enough cement to cover and isolate all hydrocarbon-bearing zones and isolate abnormal pressure
intervals from normal 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.
Use enough cement to cover or isolate all hydrocarbonbearing zones above the shoe.
As a minimum, you must cement the annular space at
least 500 feet above the casing shoe and 500 feet
above the uppermost hydrocarbon-bearing zone.
Same as cementing requirements for specific casing
types. For example, a liner used as intermediate casing must be cemented according to the cementing requirements for intermediate casing.
(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.
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Casing type
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(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.
Minimum test pressure
(1) Drive or Structural ...............................................................................
(2) Conductor ............................................................................................
(3) Surface, Intermediate, and Production ...............................................
(b) You must ensure proper
installation of casing or liner in the
subsea wellhead or liner hanger.
§ 250.423 What are the requirements for
pressure testing casing?
Not required.
200 psi.
70 percent of its minimum internal yield.
(1) You must ensure that the latching
mechanisms or lock down mechanisms
are engaged upon installation of each
casing string or liner.
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(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
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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.
§ 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.
§ 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 recement, repair the liner, or run
additional casing/liner to provide a
proper seal.
§ 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.
§ 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.
§ 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 conditions that warrant revising your casing design,
(b) Need to increase casing setting depths more than 100 feet true
vertical depth (TVD) from the approved APD due to conditions encountered during drilling operations,
(c) Have indication of inadequate cement job (such as lost returns, cement channeling, or failure of equipment),
Submit a revised casing program to the District Manager for approval.
(d) Inadequate cement job,
(e) Primary cement job that did not isolate abnormal pressure intervals,
(f) Decide to produce a well that was not originally contemplated for
production,
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(g) Want to drill a well without setting conductor casing,
(h) Need to use less than required cement for the surface casing during floating drilling operations to provide protection from burst and
collapse pressures,
(i) Cement across a permafrost zone,
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Submit those changes to the District Manager for approval.
(1) Pressure test the casing shoe; (2) Run a temperature survey; (3)
Run a cement bond log; or (4) Use a combination of these techniques.
Re-cement or take other remedial actions as approved by the District
Manager.
Isolate those intervals from normal pressures by squeeze cementing
before you complete; suspend operations; or abandon the well,
whichever occurs first.
Have at least two cemented casing strings (does not include liners) in
the well. Note: All producing wells must have at least two cemented
casing strings.
Submit geologic data and 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.
Submit information to the District Manager that demonstrates the use
of less cement is necessary.
Use cement that sets before it freezes and has a low heat of hydration.
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If you encounter the following situation:
Then you must . . .
(j) Leave the annulus opposite a permafrost zone uncemented,
Fill the annulus with a liquid that has a freezing point below the minimum permafrost temperature and minimizes opposite a corrosion.
Diverter System Requirements
§ 250.430
system?
When must I install a diverter
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.
§ 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.
§ 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 instead of rigid pipe,
(b) Use only one spool outlet for your diverter system,
Use flexible hose that has integral end couplings.
(1) Have branch lines that meet the minimum internal diameter requirements; and (2) Provide downwind diversion capability.
Use a spool that has dual outlets with an internal diameter of at least 8
inches.
Maintain an appropriate vessel heading to provide for downwind diversion.
(c) Use a spool with an outlet with an internal diameter of less than 10
inches on a surface wellhead,
(d) Use a single diverter line for floating drilling operations on a dynamically positioned drillship,
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§ 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 divertercontrol 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 pressuretest 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.
§ 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
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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
§ 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.
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§ 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
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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.
§ 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-controlled, hydraulically operated BOPs ..
You must have at least one annular BOP, two BOPs equipped with
pipe rams, and one BOP equipped with blind-shear rams. The blindshear 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 provide fast closure of the BOP
components and to operate all critical functions in case of a loss of
the power fluid connection to the surface.
(d) Have a subsea BOP stack equipped with remotely operated vehicle
(ROV) intervention capability.
(e) Maintain an ROV and have a trained ROV crew on each floating
drilling rig on a continuous basis. The crew must examine all ROV
related well control equipment (both surface and subsea) to ensure
that it is properly maintained and capable of shutting in the well during emergency operations.
(f) Provide autoshear and deadman systems for dynamically positioned
rigs.
(g) Have operational or physical barrier(s) on BOP control panels to
prevent accidental disconnect functions.
(h) Clearly label all control panels for the subsea BOP system ..............
(i) Develop and use a management system for operating the BOP system, including the prevention of accidental or unplanned disconnects
of the system.
(j) Establish minimum requirements for personnel authorized to operate
critical BOP equipment.
(k) Before removing the marine riser, displace the fluid in the riser with
seawater.
(l) Install the BOP stack in a glory hole when in ice-scour area .............
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§ 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
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The accumulator system must meet or exceed the provisions of Section 13.3, Accumulator Volumetric Capacity, in API RP 53, Recommended Practices for Blowout Prevention Equipment Systems for
Drilling Wells (as incorporated by reference in § 250.198). The District Manager may approve a suitable alternate method.
At a minimum, the ROV must be capable of closing one set of pipe
rams, closing one set of blind-shear rams and unlatching the LMRP.
The crew must be trained in the operation of the ROV. The training
must include simulator training on stabbing into an ROV intervention
panel on a subsea BOP stack.
(1) Autoshear system means a safety system that is designed 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.
Incorporate enable buttons on control panels to ensure two-handed operation for all critical functions.
Label other BOP control panels such as hydraulic control panel.
The management system must include written procedures for operating
the BOP stack and LMRP (including proper techniques to prevent
accidental disconnection of these components) and minimum knowledge requirements for personnel authorized to operate and maintain
BOP components.
Personnel must have:
(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.
You must maintain sufficient hydrostatic pressure or take other suitable
precautions to compensate for the reduction in pressure and to
maintain a safe and controlled well condition.
Your glory hole must be deep enough to ensure that the top of the
stack is below the deepest probable ice-scour depth.
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.
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(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
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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.
§ 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.
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§ 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
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available on the rig floor to fit the casing
string being run in the hole;
(h) All required manual and remotecontrolled kelly valves, drill-string
safety valves, and comparable-type
valves (i.e., kelly-type valve in a topdrive system) must be essentially fullopening; and
(i) The drilling crew must have ready
access to a wrench to fit each manual
valve.
§ 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 § 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.
§ 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.
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§ 250.448 What are the BOP pressure tests
requirements?
When you pressure test the BOP
system, you must conduct a lowpressure 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).
§ 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 blindshear ram BOP during stump tests and
at all casing points;
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(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 wellpressure 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.
§ 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.
§ 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 required pressure during a test,
(b) Need to repair or replace a surface or subsea BOP system,
Correct the problem and retest the affected equipment.
First place the well in a safe, controlled condition (e.g., before drilling
out a casing shoe or after setting a cement plug, bridge plug, or a
packer).
Record the reason for postponing the test in the driller’s report and
conduct the required BOP test on the first trip out of the hole.
Suspend further drilling operations until that station or pod is operable.
Install two or more sets of 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.
Test the ram bonnets before running casing.
Demonstrate that your well control procedures or the anticipated well
conditions will not place demands above its rated working pressure
and obtain approval from the District Manager.
Install the BOP stack in a 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.
Retrieve, physically inspect, and conduct a full pressure test of the
BOP stack after the situation is fully controlled.
(c) Need to postpone a BOP test due to well-control problems such as
lost circulation, formation fluid influx, or stuck drill pipe,
(d) BOP control station or pod that does not function properly,
(e) Want to drill with a tapered drill-string,
(f) Install casing rams in a BOP stack,
(g) Want to use an annular BOP with a rated working pressure less
than the anticipated surface pressure,
(h) Use a subsea BOP system in an ice-scour area,
(i) You activate blind-shear rams or casing shear rams during a well
control situation, in which pipe or casing is sheared,
Drilling Fluid Requirements
mstockstill on DSK4VPTVN1PROD with RULES2
§ 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.
§ 250.456 What safe practices must the
drilling fluid program follow?
Your drilling fluid program must
include the following safe practices:
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(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
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(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
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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 industryaccepted 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,
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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.
§ 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.
§ 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.
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(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.
§ 250.459 What are the safety
requirements for drilling fluid-handling
areas?
You must classify drilling fluidhandling 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 § 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 § 250.198). In areas where
dangerous concentrations of
combustible gas may accumulate, you
must install and maintain a ventilation
system and gas monitors. Drilling fluidhandling 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
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as far as practicable from hazardous
areas; and
(d) Alarms that activate when the
mechanical ventilation system fails.
Other Drilling Requirements
§ 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.
§ 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-Gridnorth 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.
§ 250.462 What are the requirements for
well-control drills?
You must conduct a weekly wellcontrol 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.
§ 250.463
rules?
Who establishes field drilling
(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
§ 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.
Then you must . . .
And . . .
(1) Intend to revise your drilling
plan, change major drilling equipment, or plugback,
mstockstill on DSK4VPTVN1PROD with RULES2
When you . . .
Submit form BSEE–0124 or request oral approval,
(2) Determine a well’s final surface
location, water depth, and the rotary kelly bushing elevation,
(3) Move a drilling unit from a
wellbore before completing a
well,
Immediately Submit a form BSEE–
0124,
Receive written or oral approval from the District Manager before you
begin the intended 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.
Submit a plat certified by a registered land surveyor that meets the
requirements of § 250.412.
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Submit forms BSEE–0124 and
BSEE–0125 within 30 days after
the suspension of wellbore operations,
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Submit appropriate copies of the well records.
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(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 § 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 (§ 250.468(b)).
§ 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
§ 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;
64525
(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.
§ 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,
(b) Casing and liner pressure tests, diverter tests, and BOP tests,
(c) Completion of a well or of any workover activity that materially alters the completion configuration or affects a hydrocarbon-bearing
zone,
Ninety days after you complete drilling operations.
Two years after the completion of drilling operations.
You permanently plug and abandon the well or until you forward the
records with a lease assignment.
§ 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.
mstockstill on DSK4VPTVN1PROD with RULES2
§ 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
§ 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
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(d) Other reports and records of
operations.
Hydrogen Sulfide
§ 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, wellcompletion/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
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(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.
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Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations
(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, wellworkover, 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
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use to safely relocate the vessels in an
emergency;
(9) How you will provide protectivebreathing 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, wellworkover, 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
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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 § 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
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(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 highvisibility yellow color with black
lettering as follows:
Wording
12 inches ...................
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Letter height
Danger.
Poisonous Gas.
Hydrogen Sulfide.
Do not approach if
red flag is flying.
Do not approach if
red lights are flashing.
7 inches .....................
(Use appropriate
wording at right).
(4) May I use existing signs? You may
use existing signs containing the words
‘‘Danger-Hydrogen Sulfide-H2S,’’
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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 wellworkover 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-
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64527
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
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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;
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(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 § 250.198).
(iii) Make available at least two voicetransmission 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 protectivebreathing 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, wellcompletion 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
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apparatus bottles. The cascade air-bottle
system may be recharged by a highpressure 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 cementpump 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 15minute 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 §§ 250.188 through
250.190.
(m) Do I need to use special drilling,
completion and workover fluids or
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procedures? When working in an area
classified as H2S present or H2S
unknown:
(1) You may use either water- or oilbase muds in accordance with
§ 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 waterbase 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 mudseparator equipment depending on
volume, pressure and concentration of
H2S. The equipment must be designed
to recover well-control fluids and burn
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the gases separated from the wellcontrol 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 § 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,
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64529
flanges, and related equipment that is
designed for H2S service.
(2) Use BOP system components,
wellhead, pressure-control equipment,
and related equipment exposed to H2Sbearing fluids in conformance with
NACE Standard MR0175–03 (as
specified in § 250.198).
(3) Use temporary downhole wellsecurity 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 protectivebreathing 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 workoverstrings 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
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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.
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Subpart E—Oil and Gas WellCompletion Operations
§ 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.
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 § 250.490 of this part as
well as the appropriate requirements of
this subpart.
§ 250.505
Subsea completions.
No subsea well completion shall be
commenced until the lessee obtains
§ 250.501 Definition.
written approval from the District
Manager in accordance with § 250.513
When used in this subpart, the
of this part. That approval shall be
following term shall have the meaning
based upon a case-by-case
given below:
Well-completion operations means the determination that the proposed
work conducted to establish the
equipment and procedures will
production of a well after the
adequately control the well and permit
production-casing string has been set,
safe production operations.
cemented, and pressure-tested.
§ 250.506
§ 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 wellbay 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 backpressure valve prior to removing the
blowout preventer (BOP) system and
installing the tree.
§ 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.
§ 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 § 250.490 of this part), the
lessee shall take appropriate precautions
to protect life and property on the
platform or completion unit, including,
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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.
§ 250.507
[Reserved]
§ 250.508
[Reserved]
§ 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.
§ 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.
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§ 250.511
Traveling-block safety device.
All units being used for wellcompletion 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 drillline slipping operation. The results of
the operational check must be entered
in the operations log.
§ 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, wellcompletion 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.
§ 250.513 Approval and reporting of wellcompletion 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 wellcompletion on those forms (see
§§ 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 wellcompletion 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 wellcompletion 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 § 250.490 of
this part; and
(5) Payment of the service fee listed in
§ 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 § 250.186.
§ 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 wellcompletion 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
64531
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 wellcontrol 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.
§ 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:
When . . .
The minimum BOP stack must include . . .
(1) The expected pressure is less than 5,000 psi,
Three BOPs consisting of an annular, one set of pipe rams, and one
set of blind-shear rams.
Four BOPs consisting of an annular, two sets of pipe rams, and one
set of blind-shear rams.
Four BOPs consisting of an annular, one set of pipe rams, one set of
dual pipe rams, and one set of blind-shear rams.
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.
The requirements in § 250.442(a) of this part.
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(2) The expected pressure is 5,000 psi or greater or you use multiple
tubing strings,
(3) You handle multiple tubing strings simultaneously,
(4) You use a tapered drill string,
(5) You use a subsea BOP stack,
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(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 workstring 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 wellcompletions must meet the
requirements in § 250.442 of this part.
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§ 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
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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 blindshear 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;
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(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 wellcontrol 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 § 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.
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(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
§ 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
64533
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.
§ 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 wells,
(2) subsea wells,
(3) hybrid * wells,
the wellhead,
the tubing head,
the surface wellhead,
all annuli (A, B, C, D, etc., annuli).
the production casing annulus (A annulus).
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 § 250.801 of this part.
Casing Pressure Management
§ 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
§ 250.198) and the requirements of
§§ 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.
§ 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:
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If you have . . .
you must monitor . . .
with a minimum one pressure data point recorded per
. . .
(a) fixed platform wells,
(b) subsea wells,
(c) hybrid wells,
(d) wells operating under a casing pressure request on a
manned fixed platform,
(e) wells operating under a casing pressure request on
an unmanned fixed platform,
monthly,
continuously,
continuously,
daily,
month for each casing.
day for the production casing.
day for each riser and/or the production casing.
day for each casing.
weekly,
week for each casing.
§ 250.520 When do I have to perform a
casing diagnostic test?
observing or imposing casing pressure
according to the following table:
(a) You must perform a casing
diagnostic test within 30 days after first
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If you have a . . .
you must perform a casing diagnostic test if . . .
(1) fixed platform well,
(2) subsea well,
the casing pressure is greater than 100 psig.
the measurable casing pressure is greater than the external hydrostatic
pressure plus 100 psig measured at the subsea wellhead.
a riser or the production casing pressure is greater than 100 psig
measured at the surface.
(3) hybrid well,
(b) You are exempt from performing a
diagnostic pressure test for the
production casing on a well operating
under active gas lift.
§ 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
§§ 250.520 and 250.522.
§ 250.522 When do I have to repeat casing
diagnostic testing?
Casing diagnostic testing must be
repeated according to the following
table:
When . . .
you must repeat diagnostic testing . . .
(a) your casing pressure request approved term has expired,
(b) your well, previously on gas lift, has been shut-in or returned to
flowing status without gas lift for more than 180 days,
immediately.
immediately on the production casing (A annulus). The production casing (A annulus) of wells on active gas lift are exempt from diagnostic
testing.
within 30 days.
within 30 days.
(c) your casing pressure request becomes invalid,
(d) a casing or riser has an increase in pressure greater than 200 psig
over the previous casing diagnostic test,
(e) after any corrective action has been 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 casing (A annulus) has pressure
exceeding 10 percent of its minimum internal yield pressure (MIYP),
except for production casings on active gas lift,
(g) your fixed platform well’s outer casing (B, C, D, etc., annuli) has a
pressure exceeding 20 percent of its MIYP,
§ 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.
§ 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
within 30 days.
once per year, not to exceed 12 months between tests.
once every 5 years, at a minimum.
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 § 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.
§ 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 § 250.524:
You must submit either . . .
to the appropriate . . .
and it must include . . .
You must also . . .
(a) a notification of corrective action; or,
District Manager and copy
the Regional Supervisor,
Field Operations,
Regional Supervisor, Field
Operations,
requirements under
§ 250.526,
submit an Application for Permit to Modify or Corrective Action Plan within 30 days of the diagnostic
test.
mstockstill on DSK4VPTVN1PROD with RULES2
(b) a casing pressure request,
§ 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;
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requirements under
§ 250.527.
(b) Area name and OCS block number;
(c) Well name and API number; and
(d) Casing diagnostic test data.
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§ 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;
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(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.
§ 250.528 What are the terms of my casing
pressure request?
mstockstill on DSK4VPTVN1PROD with RULES2
Casing pressure requests are approved
by the Regional Supervisor, Field
Operations, for a term to be determined
by the Regional Supervisor on a case-bycase basis. The Regional Supervisor may
impose additional restrictions or
requirements to allow continued
operation of the well.
§ 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
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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
§ 250.522(e).
§ 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, sidetracked, 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
§ 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.
§ 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 pumpthrough-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;
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64535
(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.
§ 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 wellbay 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 wellworkover 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.
§ 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.
§ 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 § 250.490 of this part), the
lessee shall take appropriate precautions
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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
§ 250.490 of this part as well as the
appropriate requirements of this
subpart.
§ 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 § 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.
shutdown devices. Diesel engines which
are not continuously attended shall be
equipped with automatic shutdown
devices.
§ 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.
§ 250.612
Field well-workover rules.
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.
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 wellworkover 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.
§ 250.607
[Reserved]
§ 250.613 Approval and reporting for wellworkover operations.
§ 250.608
[Reserved]
(a) No well-workover operation except
routine ones, as defined in § 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 wellworkover 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 § 250.490 of
this part; and
(4) Payment of the service fee listed in
§ 250.125.
(c) The following additional
information shall be submitted with
§ 250.606
Crew instructions.
§ 250.609 Well-workover structures on
fixed platforms.
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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 wellservicing 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.
§ 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
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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.
§ 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 wellworkover 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
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gains and losses. This indicator shall
include both a visual and an audible
warning device.
§ 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-
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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:
When . . .
The minimum BOP stack must include . . .
(1) The expected pressure is less than 5,000 psi,
Three BOPs consisting of an annular, one set of pipe rams, and one
set of blind-shear rams.
Four BOPs consisting of an annular, two sets of pipe rams, and one
set of blind-shear rams.
Four BOPs consisting of an annular, one set of pipe rams, one set of
dual pipe rams, and one set of blind-shear rams.
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.
The requirements in § 250.442(a) of this part.
(2) The expected pressure is 5,000 psi or greater or you use multiple
tubing strings,
(3) You handle multiple tubing strings simultaneously,
(4) You use a tapered drill string,
(5) You use a subsea BOP stack,
(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 smalldiameter jointed pipe (usually 3⁄4 inch to
11⁄4 inch) as a work string, i.e., smalltubing operations, shall include the
following:
(1) Two sets of pipe rams, and
(2) One set of blind rams.
(e) The subsea BOP system for wellworkover operations must meet the
requirements in § 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:
(c) The BOP systems for wellworkover 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.
BOP system when expected
surface pressures are less than or equal to
3,500 psi
BOP system when expected
surface pressures are greater than 3,500 psi
BOP system for wells with returns taken
through an outlet on the BOP stack
Stripper or annular-type well control component
Stripper or annular-type well control component.
Hydraulically-operated blind rams ...................
Hydraulically-operated shear rams ..................
Kill line inlet ......................................................
Hydraulically-operated two-way slip rams .......
Stripper or annular-type well control component.
Hydraulically-operated blind rams
Hydraulically-operated shear rams.
Kill line inlet.
Hydraulically-operated two-way slip rams.
Hydraulically-operated pipe rams.
A flow tee or cross.
Hydraulically-operated pipe rams.
Hydraulically-operated blind-shear rams on
wells with surface pressures > 3,500 psi. As
an option, the pipe rams can be placed
below the blind-shear rams. The blind-shear
rams should be located as close to the tree
as practical.
Hydraulically-operated blind rams ......................
Hydraulically-operated shear rams .....................
Kill line inlet ........................................................
Hydraulically-operated two-way slip rams ..........
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Hydraulically-operated pipe rams .......................
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Hydraulically-operated pipe rams ....................
Hydraulically-operated
blind-shear
rams.
These rams should be located as close to
the tree as practical.
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(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 hydraulicactuating system that provides sufficient
accumulator capacity to close-openclose 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.
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(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 workstring 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.
§ 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 highpressure 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
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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.
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(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.
§ 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 § 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
64539
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
§ 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.
§ 250.618
Tubing and wellhead equipment.
The lessee shall comply with the
following requirements during wellworkover 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 wells,
(ii) subsea wells,
(iii) hybrid* wells,
the wellhead,
the tubing head,
the surface wellhead,
all annuli (A, B, C, D, etc., annuli).
the production casing annulus (A annulus).
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.
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* 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
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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 § 250.801 of this part.
§ 250.619
Wireline operations.
The lessee shall comply with the
following requirements during routine,
as defined in § 250.601 of this part, and
nonroutine wireline workover
operations:
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(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.
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(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
§ 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-stabilizedunits (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, §§ 250.900
through 250.921 of this part.
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§ 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. Surfacecontrolled and subsurface-controlled
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SSSVs and safety valve locks and
landing nipples installed in the OCS
shall conform to the requirements in
§ 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 surfacecontrolled 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 subsurfacecontrolled SSSVs in lieu of a surfacecontrolled 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 surfacecontrolled 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
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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 § 250.198).
(f) Subsurface safety devices in shutin 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 noflow 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
§ 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 § 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
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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
§ 250.804 of this part.
(i) Additional safety equipment. All
tubing installations in which a wirelineor 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. Surfacecontrolled 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.
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§ 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 § 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 § 250.1004.
(c) Specification for surface safety
valves (SSV) and underwater safety
valves (USV). All wellhead SSVs, USVs,
and their actuators which are installed
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in the OCS shall conform to the
requirements in § 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 § 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 hydrocarbonhandling vessels.
(2) A schematic piping flow diagram
(API RP 14C, Figure E, as incorporated
by reference in § 250.198) and the
related Safety analysis Function
Evaluation chart (API RP 14C,
subsection 4.3c, as incorporated by
reference in § 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 § 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 § 250.198), and outlining
areas in which potential ignition
sources, other than electrical, are to be
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64541
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 fireand 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 § 250.125.
The fee you must pay will be
determined by the number of
components involved in the review and
approval process.
§ 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
§ 250.802 of this subpart and the
requirements of API RP 14C (as
incorporated by reference in § 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,
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Rating, Repair, and Alteration, API 510
(except Sections 5.8 and 9.5) (as
incorporated by reference in § 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 valvesizing 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 pressurerecorder 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 lowpressure 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 § 250.198). The lessee shall
use pressure recorders to establish the
new operating pressure ranges of
flowlines at any time when there is a
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significant change in operating
pressures. The most recent pressurerecorder 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 § 250.198);
(B) Determine that the unbonded
flexible pipe is suitable for its intended
purpose on the lease or pipeline rightof-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
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with the IVA requirements of API Spec
17J (as incorporated by reference in
§ 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 § 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 surfacecontrolled 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 § 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
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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
§ 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 § 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 openand 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.
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(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 fireprotection 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
§ 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 § 250.198).
(ii) All detection systems shall be
capable of continuous monitoring. Firedetection 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
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64543
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
§ 250.198).
(10) Electrical equipment. Electrical
equipment and systems shall be
designed, installed, and maintained in
accordance with the requirements in
§ 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, Xray, 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 § 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
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requirements in §§ 250.109 through
250.113 of this part.
mstockstill on DSK4VPTVN1PROD with RULES2
§ 250.804 Production safety-system
testing and records.
(a) Inspection and testing. The safetysystem 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 § 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 § 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 benchtested 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
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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
§ 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 § 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.
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(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 surfacecontrolled 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.
§ 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.
§ 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 § 250.198); and
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(ii) API Spec Q1, Specification for
Quality Programs for the Petroleum,
Petrochemical and Natural Gas Industry
(as incorporated by reference in
§ 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 § 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 § 250.807.
(4) For information on all standards
mentioned in this section, see § 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.
§ 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
64545
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.
§ 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 § 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
§ 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 § 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 approval
Conditions for conducting the activity
(1) Install a platform. This includes placing a newly constructed platform at a location or moving an existing platform to a new site.
(i) You must adhere to the requirements of this subpart, including the
industry standards in § 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.
(i) You must adhere to the requirements of this subpart, including the
industry standards in § 250.901.
(ii) Before you make a major modification to a floating platform, you
must obtain approval from both the BSEE and the USCG for the
modification.
(i) You must adhere to the requirements of this subpart, including the
industry standards in § 250.901.
(ii) Before you make a major repair to a floating platform, you must obtain approval from both the BSEE and the USCG for the repair.
(i) The Regional Supervisor 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.
(2) Major modification to any platform. This includes any structural
changes that materially alter the approved plan or cause a major deviation from approved operations and any modification that increases
loading on a platform by 10 percent or more.
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(3) Major repair of damage to any platform. This includes any corrective operations involving structural members affecting the structural
integrity of a portion or all of the platform.
(4) Convert an existing platform at the current location for a new purpose.
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Conditions for conducting the activity
(5) Convert an existing mobile offshore drilling unit (MODU) for a new
purpose.
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Activity requiring application and approval
(i) The Regional Supervisor 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 §§ 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.
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§ 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 § 250.198);
(2) ACI 357R–84, Guide for the Design
and Construction of Fixed Offshore
Concrete Structures, 1984; reapproved
1997 (incorporated by reference at
§ 250.198);
(3) ANSI/AISC 360–05, Specification
for Structural Steel Buildings, (as
specified in § 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 § 250.198);
(5) API Bulletin 2INT–EX, Interim
Guidance for Assessment of Existing
Offshore Structures for Hurricane
Conditions, (as incorporated by
reference in § 250.198);
(6) API Bulletin 2INT–MET, Interim
Guidance on Hurricane Conditions in
the Gulf of Mexico, (as incorporated by
reference in § 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 § 250.198);
(8) API RP 2FPS, Recommended
Practice for Planning, Designing, and
Constructing Floating Production
Systems, (as incorporated by reference
in § 250.198);
(9) API RP 2I, In-Service Inspection of
Mooring Hardware for Floating Drilling
Units (as incorporated by reference in
§ 250.198);
(10) API RP 2RD, Design of Risers for
Floating Production Systems (FPSs) and
Tension-Leg Platforms (TLPs), (as
incorporated by reference in § 250.198);
(11) API RP 2SK, Recommended
Practice for Design and Analysis of
Station Keeping Systems for Floating
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Structures, (as incorporated by reference
in § 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 § 250.198);
(13) API RP 2T, Recommended
Practice for Planning, Designing and
Constructing Tension Leg Platforms, (as
incorporated by reference in § 250.198);
(14) API RP 14J, Recommended
Practice for Design and Hazards
Analysis for Offshore Production
Facilities, (as incorporated by reference
in § 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
§ 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
§ 250.198);
(17) ASTM Standard C 150–07,
approved May 1, 2007, Standard
Specification for Portland Cement (as
incorporated by reference in § 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 § 250.198);
(19) ASTM Standard C 595–08,
approved January 1, 2008, Standard
Specification for Blended Hydraulic
Cements (as incorporated by reference
in § 250.198);
(20) AWS D1.1, Structural Welding
Code—Steel, including Commentary, (as
incorporated by reference in § 250.198);
(21) AWS D1.4, Structural Welding
Code—Reinforcing Steel, (as
incorporated by reference in § 250.198);
(22) AWS D3.6M, Specification for
Underwater Welding, (as incorporated
by reference in § 250.198);
(23) NACE Standard MR0175, Sulfide
Stress Cracking Resistant Metallic
Materials for Oilfield Equipment, (as
incorporated by reference in § 250.198);
(24) NACE Standard RP0176–2003,
Item No. 21018, Standard
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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 § 250.141.
(c) For information on the standards
mentioned in this section, and where
they may be obtained, see § 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:
Industry standard
Applicable to . . .
(1) ACI Standard 318–95, Building Code Requirements for Reinforced Concrete (ACI 318–95) and Commentary (ACI 318R–95),
(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 Construction of Fixed Offshore Concrete Structures, 1984; reapproved 1997,
(17) API RP 14J, RP for Design and Hazards Analysis for Offshore Production Facilities;
(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
§ 250.902 What are the requirements for
platform removal and location clearance?
You must remove all structures
according to §§ 250.1725 through
250.1730 of Subpart Q—
Decommissioning Activities of this part.
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§ 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 § 250.919 of this
subpart; and
(5) Records of repairs not covered in
the inspection report submitted under
§ 250.919(b).
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(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 § 250.905(j).
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Fixed and floating platform, as appropriate.
Fixed platforms.
Floating platforms.
Platform Approval Program
§ 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 §§ 250.904 through 250.908
of this subpart. Completing these
requirements will satisfy BSEE criteria
for approval of fixed platforms of a
proven design that will be placed in the
shallow water areas (≤ 400 ft.) of the
Gulf of Mexico OCS.
(b) The requirements of the Platform
Approval Program must be met by all
platforms on the OCS. Additionally, if
you want approval for a floating
platform; a platform of unique design; or
a platform being installed in deepwater
(≤ 400 ft.) or a frontier area, you must
also meet the requirements of the
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§ 250.905 How do I get approval for the
installation, modification, or repair of my
platform?
Platform Verification Program. The
requirements of the Platform
Verification Program are described in
§§ 250.909 through 250.918 of this
subpart.
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 designation, lease number, area, name, and block number, and
the type of facility your facility (e.g., drilling,
production, 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.
Latitude and longitude coordinates, Universal
Mercator grid-system coordinates, state
plane coordinates in the Lambert or Transverse Mercator 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.
Platform dimensions and orientation, elevations relative to M.L.L.W. (Mean Lower
Low Water), and pile sizes and penetration.
The approved for construction fabrication
drawings should be submitted 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.
A summary of the environmental data described in the applicable standards referenced under § 250.901(a) of this subpart
and in § 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.
Loading information (e.g., live, dead, environmental), structural information (e.g., designlife; 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).
All studies pertinent to platform design or installation, e.g., oceanographic and/or soil
reports including the overall site investigative report required in § 250.906.
Loads imposed by jacket; decks; 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.
You must submit three copies. If, your facility
is subject to the Platform Verification Program (PVP), you must submit four copies.
(b) Location plat .................................................
(c) Front, Side, and Plan View drawings ...........
(d) Complete set of structural drawings .............
(e) Summary of environmental data ...................
(f) Summary of the engineering design data .....
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(g) Project-specific studies used in the platform
design or installation.
(h) Description of the loads imposed on the facility.
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Your plat must be drawn to a scale of 1 inch
equals 2,000 feet and include the coordinates of the lease block boundary lines.
You must submit three copies.
Your drawing sizes must not exceed 11″ x
17″. You must submit three copies (four
copies for PVP applications).
Your drawing sizes must not exceed 11″ x
17″. You must submit one copy.
You must submit one copy.
You must submit one copy.
You must submit one copy of each study.
You must submit one copy.
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Required submittal
Required contents
(i) Summary of safety factors utilized .................
A summary of pertinent derived 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.
This plan is described in § 250.919 .................
The following statement: ‘‘The design of this
structure has been certified by a recognized
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)’’.
(j) A copy of the in-service inspection plan ........
(k) Certification statement ..................................
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Other requirements
You must submit one copy.
You must submit one copy.
An authorized company representative must
sign the statement. You must submit one
copy.
(l) Payment of the service fee listed in
§ 250.125.
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§ 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.
§ 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.
§ 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
§ 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 redundancy to prevent catastrophic failure of the platform or structure under consideration,
(2) There is not sufficient structural redundancy to prevent catastrophic
failure of the platform or structure,
The results of the analysis must indicate a maximum calculated life of
twice the design life of the platform.
The results of a fatigue analysis must indicate a minimum calculated
life or three times the design life of the platform.
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If . . .
Then . . .
(3) The desirable degree of redundancy is significantly reduced as a
result of fatigue damage,
The results of a fatigue analysis must indicate a minimum calculated
life of three times the design life of the platform.
(b) The documents incorporated by
reference in § 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
§ 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 §§ 250.904
through 250.908 of this subpart.
§ 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 buoyant offshore facility that does
not have a ship-shaped hull,
The entire platform is subject to the Platform 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.
Only the following structures that may be 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.
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(2) Your new floating platform is a buoyant offshore facility with a shipshaped hull,
(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.
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§ 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 § 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
§ 250.901(a) of this subpart;
(b) Comply with all the requirements
of the Platform Approval Program found
in §§ 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 § 250.912;
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(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 §§ 250.916,
250.917, and 250.918 will be submitted
to the Regional Supervisor for each
phase. On the timeline, you must breakout 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 § 250.912;
(f) Follow the additional requirements
in §§ 250.913 through 250.918;
(g) Obtain approval for modifications
to approved plans and for major
deviations from approved installation
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procedures from the Regional
Supervisor; and
(h) Comply with applicable USCG
regulations for floating OCS facilities.
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§ 250.912 What plans must I submit under
the Platform Verification Program?
If your platform, associated structure,
or major modification meets the criteria
in § 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 § 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 postinstallation verification inspection.
(d) You must combine fabrication
verification and installation verification
plans for manmade islands or platforms
fabricated and installed in place.
§ 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.
§ 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.
§ 250.915 What are the CVA’s primary
responsibilities?
(a) The CVA must conduct specified
reviews according to §§ 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 § 250.901(a); the alternative
codes, rules, and standards approved
under § 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.
§ 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 facilities,
Conduct an independent assessment of all proposed:
(i) Planning criteria;
(ii) Operational requirements;
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Type of facility . . .
The CVA must . . .
(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.
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.
(2) For all floating facilities,
(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
§ 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.
§ 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
floating facilities,
Make periodic onsite inspections while fabrication is in 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.
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.
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(2) For all floating facilities,
(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
§ 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;
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(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
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recommendation has been previously
made in an interim report; and
(6) Provide any additional comments
that the CVA deems necessary.
§ 250.918 What are the CVA’s primary
duties during the installation phase?
(a) The CVA must use good
engineering judgment and practice in
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of the installation activities.
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(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.
(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.
(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.
Survey the platform after transportation to the approved location.
(i) Equipment;
(ii) Procedures; and
(iii) Recordkeeping.
(2) Witness (for a fixed or floating platform),
(3) Witness (for a floating platform),
(4) Conduct an onsite survey,
(5) Spot-check as necessary to determine compliance with the applicable documents listed
in § 250.901(a); the alternative codes, rules
and standards approved under § 250.901(b);
the requirements listed in § 250.903 and
§§ 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
§ 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
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§ 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
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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 § 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
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remediation plans. Under
§§ 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
§ 250.900(c).
§ 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 § 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
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§ 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.
§ 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 § 250.908 are met or
exceeded.
(b) If the calculated life of a joint or
member does not meet the criteria of
§ 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
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§ 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
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fee listed in § 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 § 250.1001,
must meet the requirements in
§§ 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 rightof-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 abovewater 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.
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(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
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§ 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;
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(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).
§ 250.1002
pipelines.
Design requirements for DOI
(a) The internal design pressure for
steel pipe shall be determined in
accordance with the following formula:
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For limitations see section 841.121 of
American National Standards Institute
(ANSI) B31.8 (as incorporated by
reference in § 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
§ 250.198), API Spec 6D (as
incorporated by reference in § 250.198),
or the equivalent. A valve may not be
used under operating conditions that
exceed the applicable pressuretemperature 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
§ 250.198).
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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 § 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 rightof-way grant if the Regional Supervisor
determines that the lessee or right-ofway 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).
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(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
§ 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.
mstockstill on DSK4VPTVN1PROD with RULES2
§ 250.1003 Installation, testing, and repair
requirements for DOI pipelines.
(a)(1) Pipelines greater than 85⁄8
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
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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.
§ 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
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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 lowpressure 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 automaticand 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 tiein 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 § 250.198).
The setting levels for the PSHL devices
are specified in paragraph (b)(3) of this
section.
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(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.
§ 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
64557
calculated or calculations indicate a life
expectancy of less than 20 years, such
pipelines shall be inspected annually by
taking measurements of pipe-toelectrolyte potential.
§ 250.1006 How must I decommission and
take out of service a DOI pipeline?
(a) The requirements for
decommissioning pipelines are listed in
§ 250.1750 through § 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,
(2) More than 1 year but less than 5 years,
(3) 5 or more years,
Isolate the pipeline with a blind flange or a closed block valve at each end of the pipeline.
Flush and fill the pipeline with inhibited seawater.
Decommission the pipeline according to §§ 250.1750–250.1754.
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§ 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; pressureregulating devices (including backpressure 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,
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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;
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(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 § 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-ofway 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.
§ 250.1008
Reports.
(a) The lessee, or right-of-way holder,
shall notify the Regional Supervisor at
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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 § 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
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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
§ 250.1005(b) of this part shall be
submitted to the Regional Supervisor by
the lessee before March of each year.
§ 250.1009 Requirements to obtain
pipeline right-of-way grants.
(a) In addition to applicable
requirements of §§ 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.
§ 250.1010 General requirements for
pipeline right-of-way holders.
An applicant, by accepting a right-ofway 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
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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 rightof-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 rightof-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 rightof-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-ofway 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).
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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 § 250.1019 of this part.
§ 250.1011
64559
[Reserved]
§ 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 of less than 200 meters;
You must pay ONRR, under the regulations at 30 CFR part 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.
You must pay ONRR, under the regulations at 30 CFR part 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.
(2) Your accessory site is located in water
depths of 200 meters or greater;
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(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-ofuse grant and easement under
§ 250.1013.
§ 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
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having jurisdiction in accordance with
the provisions of 43 U.S.C. 1349.
§ 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.
§ 250.1015 Applications for pipeline rightof-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
§ 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 § 250.1012 of this
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subpart, as well as the service fees listed
in § 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
§ 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
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(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-ofway. 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.
mstockstill on DSK4VPTVN1PROD with RULES2
§ 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 § 250.1015(c) of
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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-ofway. 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-ofway 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-ofway.
(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.
§ 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-ofway pipeline, it is determined that a
deviation from the proposed right-ofway as granted has occurred, the rightof-way holder shall—
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(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-ofway pipeline as constructed from the
proposed right-of-way as granted may be
grounds for forfeiture of the right-ofway.
(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.
§ 250.1018 Assignment of pipeline right-ofway 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-ofway grant must be accompanied by the
same showing of qualifications of the
assignees as is required of an applicant
for a ROW in § 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
§ 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.
§ 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
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Regional Supervisor. It must contain
those items addressed in §§ 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 § 250.1010(h) of
this part.
Subpart K—Oil and Gas Production
Requirements
General
§ 250.1150 What are the general reservoir
production requirements?
You must produce wells and
reservoirs at rates that provide for
economic development while
64561
maximizing ultimate recovery and
without adversely affecting correlative
rights.
Well Tests and Surveys
§ 250.1151 How often must I conduct well
production tests?
(a) You must conduct well production
tests as shown in the following table:
You must conduct:
And you must submit to the Regional Supervisor:
(1) A well-flow potential test on all new, recompleted, or reworked well
completions within 30 days of the date of first continuous production,
Form BSEE–0126, Well Potential Test Report, along with the supporting data as listed in the table in § 250.1167, within 15 days after
the end of the test period.
Results on Form BSEE–0128, Semiannual Well Test Report, of the
most recent well test obtained. This must be submitted within 45
days after the end of the calendar half-year.
(2) At least one well test during a calendar half-year for each producing
completion,
(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
§§ 250.186 and 250.197, and marked
‘‘Public Information.’’ You must submit
two copies of the supporting
information as listed in the table in
§ 250.1167 with form BSEE–0126.
mstockstill on DSK4VPTVN1PROD with RULES2
§ 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
°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
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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.
§§ 250.1153—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?
(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 § 250.125, according to the
instructions in § 250.126, and the
supporting information, as listed in the
table in § 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
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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.
§ 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
§ 250.125, according to the instructions
in § 250.126, and the supporting
information, as listed in the table in
§ 250.1167, with your request.
(c) The Regional Supervisor will
determine whether your request
maximizes ultimate recovery.
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§ 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 § 250.125, according
to the instructions in § 250.126, and the
supporting information, as listed in the
table in § 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
§ 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
§ 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 (produced natural gas which is used
on or for the benefit of lease operations such as gas used to operate
production facilities) or is used as an additive necessary to burn
waste products, such as H2S.
(2) During the restart of a facility that was shut in because of weather
conditions, such as a hurricane.
(3) During the blow down of transportation pipelines downstream of the
royalty meter.
The volume of gas flared or vented may not exceed the amount necessary for its intended purpose. Burning waste products may require
approval under other regulations.
(4) During the unloading or cleaning of a well, drill-stem testing, production testing, other well-evaluation testing, or the necessary blow
down to perform these procedures.
(5) When properly working equipment yields flash gas (natural gas released from liquid hydrocarbons as a result of a decrease in pressure, an increase in temperature, or both) from storage vessels or
other low-pressure production vessels, and you cannot economically
recover this flash gas.
(6) When the equipment works properly but there is a temporary upset
condition, such as a hydrate or paraffin plug.
mstockstill on DSK4VPTVN1PROD with RULES2
(7) When equipment fails to work properly, during equipment maintenance and repair, or when you must relieve system pressures.
(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
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Flaring or venting may not exceed 48 cumulative hours without Regional Supervisor approval.
(i) You must report the location, time, flare/vent 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.
You may not exceed 48 cumulative hours of flaring or venting per unloading or cleaning or testing operation on a single completion without Regional Supervisor approval.
You may not flare or vent more than an average of 50 MCF per day
during any calendar month without Regional Supervisor approval.
(i) For oil-well gas and gas-well flash gas (natural gas released from
condensate as a 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.
(i) For oil-well gas and gas-well flash gas, you may not exceed 48 continuous hours of 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.
Production Plan (DPP) submitted to
BOEM.
(c) The Regional Supervisor may
establish alternative approval
procedures to cover situations when you
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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
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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.
§ 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.
mstockstill on DSK4VPTVN1PROD with RULES2
§ 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 reinjecting 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
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to 30 CFR part 1202. You must value
any liquid hydrocarbons avoidably lost
or wasted under the provisions of 30
CFR part 1206.
§ 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.
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64563
(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.
§ 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-
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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
§§ 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 (§ 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
§ 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 § 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.
§ 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]
§ 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:
mstockstill on DSK4VPTVN1PROD with RULES2
WPT BSEE–
0126
(2 copies)
(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 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 applicable ........................
(c) Logs:
(1) Well log sections with tops and bottoms of the reservoir(s) and proposed or existing perforations ...............................................................
(2) Structural cross-sections showing the subject well and nearby wells
(d) Engineering data:
(1) Estimated recoverable reserves for 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 proposed conditions ...............
(3) The drive mechanism of each reservoir .............................................
(4) Pressure data, by date, and whether they are estimated or measured .......................................................................................................
(5) Production data and decline curve analysis indicative of the reservoir performance ................................................................................
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Gas cap production
Downhole
commingling
Production
within 500-ft of
a unit or lease
line
........................
✔
✔
✔
✔
✔
✔
✔
........................
✔
✔
........................
........................
✔
✔
........................
........................
........................
✔
✔
✔
✔
✔
✔
✔
........................
✔
✔
✔
✔
✔
*
........................
........................
........................
†
✔
✔
†
✔
✔
✔
✔
✔
........................
✔
✔
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✔
✔
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64565
WPT BSEE–
0126
(2 copies)
(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 as defined
under § 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 ...............................................................
(5) Explanation of why the proposed completion scenario will maximize
ultimate recovery ...................................................................................
(6) List of all wells in subject reservoirs that have ever produced or
been used for injection .........................................................................
Gas cap production
Downhole
commingling
Production
within 500-ft of
a unit or lease
line
........................
*
*
*
........................
*
*
........................
........................
✔
✔
✔
........................
........................
✔
✔
✔
✔
✔
✔
........................
✔
✔
✔
........................
✔
✔
✔
✔ Required.
† 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 § 250.125, according to
the instructions in § 250.126.
Subpart L—Oil and Gas Production
Measurement, Surface Commingling,
and Security
§ 250.1200
Production Measurement, Surface
Commingling, and Security.
Question index table.
The table in this section lists
questions concerning Oil and Gas
Frequently asked questions
CFR citation
1.
2.
3.
4.
5.
6.
7.
What are the requirements for measuring liquid hydrocarbons?
What are the requirements for liquid hydrocarbon royalty meters?
What are the requirements for run tickets?
What are the requirements for liquid hydrocarbon royalty meter provings?
What are the requirements for calibrating a master meter used in royalty meter provings?
What are the requirements for calibrating mechanical-displacement provers and tank provers?
What correction factors must a lessee use when proving meters with a mechanical displacement prover, tank prover, or
master meter?
8. What are the requirements for establishing and applying operating meter factors for liquid hydrocarbons?
9. Under what circumstances does a liquid hydrocarbon royalty meter need to be taken out of service, and what must a lessee do?
10. How must a lessee correct gross liquid hydrocarbon volumes to standard conditions?
11. What are the requirements for liquid hydrocarbon allocation meters?
12. What are the requirements for royalty and inventory tank facilities?
13. To which meters do BSEE requirements for gas measurement apply?
14. What are the requirements for measuring gas?
15. What are the requirements for gas meter calibrations?
16. What must a lessee do if a gas meter is out of calibration or malfunctioning?
17. What are the requirements when natural gas from a Federal lease is transferred to a gas plant before royalty determination?
18. What are the requirements for measuring gas lost or used on a lease?
19. What are the requirements for the surface commingling of production?
20. What are the requirements for a periodic well test used for allocation?
21. What are the requirements for site security?
22. What are the requirements for using seals?
mstockstill on DSK4VPTVN1PROD with RULES2
§ 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 § 250.198.
Terms used in Subpart L have the
following meaning:
Allocation meter—a meter used to
determine the portion of hydrocarbons
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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.
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§ 250.1202(a)
§ 250.1202(b)
§ 250.1202(c)
§ 250.1202(d)
§ 250.1202(e)
§ 250.1202(f)
§ 250.1202(g)
§ 250.1202(h)
§ 250.1202(i)
§ 250.1202(j)
§ 250.1202(k)
§ 250.1202(l)
§ 250.1203(a)
§ 250.1203(b)
§ 250.1203(c)
§ 250.1203(d)
§ 250.1203(e)
§ 250.1203(f)
§ 250.1204(a)
§ 250.1204(b)
§ 250.1205(a)
§ 250.1205(b)
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 °F) to 60.5
degrees Fahrenheit (60.5 °F) at standard
pressure base (14.73 pounds per square
inch absolute (psia)).
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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).
Application type
(i) Simple applications,
mstockstill on DSK4VPTVN1PROD with RULES2
(ii) Complex applications,
16:55 Oct 17, 2011
§ 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
§ 250.125. The service fees are divided
into two levels based on complexity as
shown in the following table.
Actions
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.
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 § 250.198,
when obtaining net standard volume
and associated measurement
parameters; and
(4) When requested by the Regional
Supervisor, provide the pipeline
VerDate Mar<15>2010
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 °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 °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).
Jkt 226001
(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 BSEEapproved components) which must be
compatible with their connected
systems:
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(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.
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(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 § 250.198);
(ii) The sample container is vaportight 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;
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(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
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MPMS (as incorporated by reference in
§ 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 mechanicaldisplacement 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 mechanicaldisplacement 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
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(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 § 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
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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 § 250.198.
§ 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
§ 250.125. The service fees are divided
into two levels based on complexity, see
table in § 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 § 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
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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 °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
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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.
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§ 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 § 250.125. The service fees
are divided into two levels based on
complexity, see table in
§ 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:
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(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.
§ 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, drainline 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.
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(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
§ 250.1300
subpart?
What is the purpose of this
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.
§ 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
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substances, and the unit operator no
longer conducts drilling or wellworkover operations (§ 250.180) under
the unit agreement, unless the Regional
Supervisor orders or approves a
suspension of production under
§ 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 netprofit-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 § 250.180, the unit operator must
request and obtain BSEE approval of a
suspension of production under
§ 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
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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
§ 250.170.
§ 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
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§ 250.1301(b), BSEE will initiate
unitization under § 250.1304.
§ 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
§ 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 § 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 § 250.125 with your request
for unitization revision.
§ 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 §§ 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 § 250.1300. The proposed
unit agreement must include a
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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.
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Subpart N—Outer Continental Shelf
Civil Penalties
Outer Continental Shelf Lands Act Civil
Penalties
§ 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.
§ 250.1401
Index table.
The following table is an index of the
sections in this subpart:
Definitions.
What is the maximum civil
penalty?
Which violations will BSEE
review for potential civil
penalties?
When is a case file developed?
When will BSEE notify me
and provide penalty information?
How do I respond to the letter of notification?
When will I be notified of the
Reviewing Officer’s decision?
What are my appeal rights?
§ 250.1402
§ 250.1402
§ 250.1403
§ 250.1404
Frm 00141
The maximum civil penalty is
$40,000 per day per violation.
§ 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.
§ 250.1405
§ 250.1406
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 § 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.
§ 250.1407
§ 250.1408
§ 250.1409
Definitions.
Fmt 4701
What is the maximum civil
§ 250.1405
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.
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§ 250.1403
penalty?
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When is a case file developed?
§ 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.
§ 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.
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§ 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.
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§ 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 leasespecific/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
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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
§ 250.1450
subpart?
What definitions apply to this
The terms used in this subpart have
the same meaning as in 30 U.S.C. 1702.
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?
(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.
§ 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).
§ 250.1453
violation?
What if I do not correct the
(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
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Notice of Noncompliance, for each
violation for as long as you do not
correct the violations.
§ 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.
§ 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
§ 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
§§ 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).
§ 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 § 250.1454. If you did not
request a hearing on the record on the
Notice of Noncompliance under
§ 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
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Appeals, U.S. Department of the
Interior, 801 North Quincy Street,
Arlington, Virginia 22203.
Penalties Without a Period To Correct
§ 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.
§ 250.1461 How will BSEE inform me of
violations without a period to correct?
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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.
§ 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
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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.
§ 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
§ 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
§§ 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).
§ 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 § 250.1462. If you
did not request a hearing on the record
on the Notice of Noncompliance under
§ 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
§ 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
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64573
the violations, your history of
compliance, and if you are a small
business.
§ 250.1471 Does the penalty affect whether
I owe interest?
If you do not pay the penalty by the
date required under § 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.
§ 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 §§ 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.
§ 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.
§ 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.
§ 250.1475
When must I pay the penalty?
(a) You must pay the amount of the
Notice of Civil Penalty issued under
§§ 250.1453 or 250.1461, if you do not
request a hearing on the record under
§§ 250.1454, 250.1456, 250.1462, or
250.1464.
(b) If you request a hearing on the
record under §§ 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
§ 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
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on the record under either §§ 250.1454,
250.1456, 250.1462, or 250.1464;
(2) You received an Administrative
Law Judge’s decision under § 250.1472,
if you obtained a stay of the accrual of
penalties pending the hearing on the
record under § 250.1455(b) or
§ 250.1463(b) and did not appeal the
Administrative Law Judge’s
determination to the IBLA under
§ 250.1473;
(3) You received an IBLA decision
under § 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 § 250.1477.
§ 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.
§ 250.1477
penalty?
How may BSEE collect the
(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 § 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 § 250.1474. The
amount of any penalty, as finally
determined, may be deducted from any
sum owing to you by the United States.
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Criminal Penalties
§ 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 § 250.1460(b), the United States
may pursue criminal penalties as
provided at 30 U.S.C. 1720, in addition
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Bonding Requirements
(2) Submit a separate surety
instrument for new amounts under
appeal until you amend the instrument
to cover the new appeals.
§ 250.1490 What standards must my
BOEM-specified surety instrument meet?
Financial Solvency Requirements
(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.
§ 250.1495
solvency?
to any authority for prosecution under
other statutes.
§ 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 BOEMspecified 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
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How do I demonstrate financial
(a) To demonstrate financial solvency
under this part, you must submit an
audited consolidated balance sheet, and,
if requested by the BOEM bondapproving 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.
§ 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 §§ 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.
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(c) If your net worth, minus the
amount we would require as surety
under §§ 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 § 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 §§ 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 businessinformation 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
§§ 250.1490 and 250.1491;
(ii) If our bond-approving officer
determines that the businessinformation 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
§§ 250.1490 and 250.1491 or pay the
obligation.
§ 250.1497 When will BOEM monitor my
financial solvency?
(a) If you are presumptively
financially solvent under § 250.1496(b),
BOEM will determine your net worth as
described under § 250.1496(b) and (c) to
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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 businessinformation or credit-reporting service
or program under § 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 §§ 250.1490 and
250.1491.
Subpart O—Well Control and
Production Safety Training
§ 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
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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.
§ 250.1501
program?
What is the goal of my training
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.
§ 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:
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(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.
§ 250.1504
methods?
May I use alternative training
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.
§ 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.
§ 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.
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§ 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.
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(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.
§ 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).
§ 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.
§ 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);
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(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
§ 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.
§ 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.
§ 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
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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.
§ 250.1603
deposit.
Determination of sulphur
(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.
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§ 250.1604
General requirements.
Sulphur lessees shall comply with
requirements of this section when
conducting well-drilling, wellcompletion, well-workover, or
production operations.
(a) Equipment movement. The
movement of well-drilling, wellcompletion, 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, wellworkover, or production operation is
being conducted on a well in zones
known to contain H2S or in zones where
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the presence of H2S is unknown (as
defined in § 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
§ 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, wellworkover 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 §§ 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 § 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, wellcompletion, 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 drillline slipping operation. The results of
the operational check must be entered
in the operations log.
§ 250.1605
Drilling requirements.
(a) Sulphur leases. Lessees of OCS
sulphur leases shall conduct drilling
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operations in accordance with
§§ 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 § 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 bottomfounded drilling unit under the sitespecific 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.
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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-MercatorGrid-north or Lambert-Grid-north shall
be made after making the magnetic-totrue-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 § 250.108 of this
subpart.
(h) Diesel-engine air intakes. Dieselengine 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 remoteoperated manual or automaticshutdown devices. Diesel engines that
are not continuously attended must be
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equipped with automatic shutdown
devices.
§ 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.
§ 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.
§ 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
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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
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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.
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§ 250.1609
Pressure testing of casing.
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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,
§ 250.1610 Blowout preventer systems and surrounding environment, and
corrosiveness, volume, and abrasiveness
system components.
of fluids. The choke manifold shall also
(a) General. The blowout preventer
meet the following requirements:
(BOP) systems and system components
(i) Manifold and choke equipment
shall be designed, installed, used,
subject to well and/or pump pressure
maintained, and tested to assure well
shall have a rated working pressure at
control.
least as great as the rated working
(b) BOP stacks. The BOP stacks shall
pressure of the ram-type BOP’s or as
consist of an annular preventer and the
otherwise approved by the District
number of ram-type preventers as
specified under paragraphs (e) and (f) of Manager;
(ii) All components of the choke
this section. The pipe rams shall be of
manifold system shall be protected from
proper size to fit the drill pipe in use.
freezing by heating, draining, or filling
(c) Working pressure. The workingpressure rating of any BOP shall exceed with proper fluids; and
(iii) When buffer tanks are installed
the surface pressure to which it may be
downstream of the choke assemblies for
anticipated to be subjected.
the purpose of manifolding the bleed
(d) BOP equipment. All BOP systems
lines together, isolation valves shall be
shall be equipped and provided with
installed on each line.
the following:
(8) Valves, pipes, flexible steel hoses,
(1) An accumulator system that
and other fittings upstream of, and
provides sufficient capacity to supply
including, the choke manifold with a
1.5 times the volume necessary to close
pressure rating at least as great as the
and hold closed all BOP equipment
rated working pressure of the ram-type
units with a minimum pressure of 200
BOP’s unless otherwise approved by the
psi above the precharge pressure,
District Manager.
without assistance from a charging
(9) A wellhead assembly with a rated
system. Accumulator regulators
working pressure that exceeds the
supplied by rig air that do not have a
pressure to which it might be subjected.
secondary source of pneumatic supply
(10) The following system
must be equipped with manual
components:
overrides or other devices alternately
(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.
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(i) A kelly cock (an essentially fullopening 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.
mstockstill on DSK4VPTVN1PROD with RULES2
§ 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
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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 blindshear 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
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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.
§ 250.1612
Well-control drills.
Well-control drills shall be conducted
for each drilling crew in accordance
with the requirements set forth in
§ 250.462 of this part or as approved by
the District Manager.
§ 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
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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.
§ 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 §§ 250.455 through
250.459 of this part, except that the
installation of an operable degasser in
the mud system as required in
§ 250.456(g) is not required for sulphur
operations.
mstockstill on DSK4VPTVN1PROD with RULES2
§ 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
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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.
§ 250.1616
training.
Supervision, surveillance, and
(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.
§ 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 § 250.125.
Before starting operations, you must
receive written approval from the
District Manager unless you received
oral approval under § 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;
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64581
(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,
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(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 § 250.186 of this part.
§ 250.1618
modify.
Application for permit to
(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 § 250.125. Before starting
operations associated with the change,
you must receive written approval from
the District Manager unless you
received oral approval under § 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 § 250.186 of this part.
mstockstill on DSK4VPTVN1PROD with RULES2
§ 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
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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 § 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.
§ 250.1620 Well-completion and wellworkover requirements.
(a) Lessees shall conduct wellcompletion and well-workover
operations in sulphur wells, bleedwells,
and brine wells in accordance with
§§ 250.1620 through 250.1626 of this
part and other provisions of this part as
appropriate (see §§ 250.501 and 250.601
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of this part for the definition of wellcompletion and well-workover
operations).
(b) Well-completion and wellworkover 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.
§ 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.
§ 250.1622 Approvals and reporting of
well-completion and well-workover
operations.
(a) No well-completion or wellworkover 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 wellcompletion 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
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the well if any subsurface equipment
has been changed.
§ 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 wellcompletion 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.
mstockstill on DSK4VPTVN1PROD with RULES2
§ 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 wellcompletion operations or for wellworkover operations with the tree
removed shall consist of the following:
(1) Three remote-controlled,
hydraulically operated preventers
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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 wellcompletion operations, or for wellworkover 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 chokeline 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 11⁄4
inch) as a work string; i.e., small-tubing
operations, shall consist of the
following:
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(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 wellworkover procedures in accordance
with § 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, workstring safety valve shall be maintained
on the rig floor at all times during wellcompletion 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.
§ 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
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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 blindshear 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 wellcompletion 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
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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.
§ 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.
§ 250.1627
Production requirements.
(a) The lessee shall conduct sulphur
production operations in compliance
with the approved Development and
Production Plan requirements of
§§ 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.
§ 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
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and Installation of Offshore Production
Platform Piping Systems (as
incorporated by reference in § 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 § 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 § 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
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pumps, metering devices, and other
hydrocarbon-handling vessels;
(2) A schematic flow diagram (API RP
14C, Figure E1, as incorporated by
reference in § 250.198) and the related
Safety Analysis Function Evaluation
chart (API RP 14C, subsection 4.3c, as
incorporated by reference in § 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 § 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 § 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 fireand 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.
§ 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
§ 250.1628 of this part).
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(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 § 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 § 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 § 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 highpressure 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
§ 250.198). Exhaust piping from diesel
engines must be equipped with spark
arresters.
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(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 § 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 fireprotection 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
§ 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 § 205.198).
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(ii) All detection systems shall be
capable of continuous monitoring. Firedetection 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
§ 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.
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§ 250.1630
records.
Safety-system testing and
(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
§ 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
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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.
§ 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.
§ 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.,
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an undue reduction in the recovery of
oil and gas from an associated
hydrocarbon accumulation).
§ 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.
§ 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
§ 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,
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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.
§ 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 rightof-way.
§ 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.
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§ 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
§§ 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.
§ 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 application [not required in
the Gulf of Mexico OCS Region].
Include information required under
§ 250.1726.
(d) Pipeline decommissioning application ...................
In the Pacific OCS Region or Alaska OCS Region,
submit the application to the Regional Supervisor
at least 2 years before production is projected to
cease.
Before removing a platform or other facility in the
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.
Within 30 days after you remove a platform or other
facility.
Before you decommission a pipeline ........................
(e) Post-pipeline decommissioning report ...................
Within 30 days after you decommission a pipeline ...
(f) Site clearance report for a platform or other facility
Within 30 days after you complete site clearance
verification activities.
(1) Before you temporarily abandon or permanently
plug a well or zone,
(b) Final removal application for a platform or other
facility.
(c) Post-removal report for a platform or other facility
(g) 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 § 250.125.
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(2) Within 30 days after you plug a well ...................
(3) Before you install a subsea protective device .....
(4) Within 30 days after you complete a protective
device trawl test.
(5) Before you remove any casing stub or mud line
suspension equipment and any subsea protective
device.
(6) Within 30 days after you complete site clearance
verification activities.
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Include information required under
§ 250.1727.
Include information required under
§ 250.1729.
Include information required under
§ 250.1751(a) or § 250.1752(a),
as applicable.
Include information required under
§ 250.1753.
Include information required under
§ 250.1743(b).
Include information required under
§§ 250.1712 and 250.1721.
Include information required under
§ 250.1717.
Refer to § 250.1722(a).
Include information required under
§ 250.1722(d).
Refer to § 250.1723.
Include information required under
§ 250.1743(a).
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Permanently Plugging Wells
§ 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.
§ 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.
§ 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 § 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).
§ 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.
§ 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.
§ 250.1715
well?
How must I permanently plug a
(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.
(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.
(i) A method to squeeze cement to all perforations;
(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.
(i) A cement plug set at least 100 feet above and below the stub end;
(2) Open hole below casing,
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(3) A perforated zone that is currently open
and not previously squeezed or isolated,
(4) A casing stub where the stub end is within
the casing,
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64589
PERMANENT WELL PLUGGING REQUIREMENTS—Continued
If you have . . .
Then you must use . . .
(5) A casing stub where the stub end is below
the casing,
(6) An annular space that communicates with
open hole and extends to the mud line,
(7) A subsea well with unsealed annulus,
(8) A well with casing,
(9) Fluid left in the hole,
(10) Permafrost areas,
(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).
§ 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).
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§ 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 § 250.1712
with a final well schematic;
(b) Description of the plugging work;
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(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.
A plug as specified in paragraph (a)(1) or (a)(2) of this section, as applicable.
A cement plug at least 200 feet long set in the annular space. For a well completed above
the ocean surface, you must pressure test each casing annulus to verify isolation.
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.
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.
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.
(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.
(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
§ 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
§ 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 § 250.1715,
except for § 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 permanenttype 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-bycase;
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(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 § 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
§ 250.1712 with a well schematic;
(2) Information required by
§ 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 § 250.1715.
The Registered Professional Engineer
must be registered in a State in the
United States. You must submit this
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certification with your APM (Form
BSEE–0124) required by § 250.1712.
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§ 250.1722 If I install a subsea protective
device, what requirements must I meet?
If you install a subsea protective
device under § 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 § 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
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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.
§ 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 § 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
§ 250.1740 through § 250.1742.
Removing Platforms and Other
Facilities
§ 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
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well as other energy-related or marinerelated 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 § 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.
§ 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.
§ 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 § 250.125. If you are
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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-ofway 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;
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(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.
§ 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).
§ 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
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64591
you used in removing the platform or
other facility were consistent with those
set forth in the approved removal
application.
§ 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.
§ 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.
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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?
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.
§ 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 § 250.1740, you must
meet all of the requirements of this
section.
(a) You must drag the trawl in a gridlike pattern as shown in the following
table:
For a . . .
You must drag the trawl across a . . .
(1)
(2)
(3)
(4)
300-foot-radius circle centered on the well location.
600-foot-radius circle centered on the well location.
1,320-foot-radius circle centered on the location of the platform.
600-foot-radius circle centered on the structure location.
Well site,
Subsea well site,
Platform site,
Single-well caisson, well protector jacket, template, or manifold,
(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.
For . . .
(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:
You must trawl . . .
And you must . . .
no closer than 100 feet to the either side of
the pipeline,
no closer than 100 feet to either side of the
pipeline,
First contact the pipeline owner or operator to
determine the condition of the pipeline before trawling over the buried pipeline.
Trawl parallel to the pipeline Do not trawl
across the pipeline.
Trawl parallel to the pipeline. Do not trawl
across the pipeline.
(1) Buried active pipelines,
(2) Unburied active pipelines that are 8 inches
in diameter or larger,
(3) Unburied smaller diameter active pipelines
in the trawl area that have obstructions (e.g.,
pipeline valves) present,
(4) Unburied active pipelines in the 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
parallel to the pipeline,
(2) Has a valid commercial trawling
license for both the vessel and its
captain.
§ 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 grid area
listed in § 250.1741(a),
ensure that the diver visually inspects 100
percent of the appropriate grid area listed in
§ 250.1741(a),
ensure that the ROV camera records videotape over 100 percent of the appropriate
grid area listed in § 250.1741(a),
Use a sonar signal with a frequency of at
least 500 kHz.
Ensure that the diver uses a search pattern of
concentric circles or parallel lines spaced
no more than 10 feet apart.
Ensure that the ROV uses a pattern of concentric circles or parallel lines spaced no
more than 10 feet apart.
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(b) A diver,
(c) An ROV (remotely operated vehicle),
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§ 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
§ 250.1750 When may I decommission a
pipeline in place?
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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.
§ 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
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accompanied by payment of the service
fee listed in § 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.
§ 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
§ 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.
§ 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;
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64593
(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.
§ 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)
§ 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 § 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
§ 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 § 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
§ 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.
§ 250.1901
program?
What is the goal of my SEMS
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.
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(b) All personnel involved with your
SEMS program must be trained to have
the skills and knowledge to perform
their assigned duties.
§ 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 § 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 § 250.1909)
(2) Safety and Environmental
Information (see § 250.1910)
(3) Hazards Analysis (see § 250.1911)
(4) Management of Change (see
§ 250.1912)
(5) Operating Procedures (see
§ 250.1913)
(6) Safe Work Practices (see
§ 250.1914)
(7) Training (see § 250.1915)
(8) Mechanical Integrity (Assurance of
Quality and Mechanical Integrity of
Critical Equipment) (see § 250.1916)
(9) Pre-startup Review (see
§ 250.1917)
(10) Emergency Response and Control
(see § 250.1918)
(11) Investigation of Incidents (see
§ 250.1919)
(12) Auditing (Audit of Safety and
Environmental Management Program
Elements) (see §§ 250.1920)
(13) Recordkeeping (Records and
Documentation) and additional BSEE
requirements (see § 250.1928).
(b) You must also include a job safety
analysis (JSA) for OCS activities
identified or discussed in your SEMS
program (see § 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
§ 250.198).
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§ 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
§ 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.
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§ 250.1904
reference.
Documents incorporated by
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.
§§ 250.1905–250.1908
[Reserved]
§ 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 § 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
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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.
§ 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 (§ 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.
§ 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;
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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.
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(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.
§ 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.
64595
(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-ofservice 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.
§ 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?
(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:
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
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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
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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.
§ 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 (§ 250.1913), the safe work
practices (§ 250.1914), and the
emergency response and control
measures (§ 250.1918). You must
document the qualifications of your
instructors. Your SEMS program must
address:
(a) Initial training for the basic wellbeing 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 (§ 250.1913),
the safe work practices (§ 250.1914), or
the emergency response and control
measures (§ 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 (§ 250.1913), the safe work
practices (§ 250.1914), or the emergency
response and control measures
(§ 250.1918).
§ 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,
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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
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§ 250.1919 What criteria for investigation
of incidents must be in my SEMS program?
are suitable for the applications for
which they will be used.
§ 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.
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§ 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 (§ 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 (§ 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 (§ 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.
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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.
§ 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 § 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
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recommendations included in API RP
75 section 12 (as specified in § 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 § 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.
§§ 250.1921–250.1923
[Reserved]
§ 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,
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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 § 250.1920, so that BSEE
may make arrangements to observe or
participate in the audit.
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§ 250.1925 May BSEE direct me to conduct
additional audits?
(a) If BSEE identifies safety or noncompliance 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 § 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
§ 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 § 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 § 250.1927.
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(c) You must provide the BSEE a copy
of your plan for addressing the
deficiencies identified in the BSEEdirected audit within 30 days of
completion of the audit as required in
§ 250.1920.
§ 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 thirdparty 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.
§ 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.
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§ 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 § 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.
§ 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.
§ 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
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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
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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.
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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;
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(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 inhouse 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.
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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.
§ 251.2
[Reserved]
§ 251.3
part.
Authority and applicability of this
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.
§§ 251.4–251.6
[Reserved]
§ 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;
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(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.
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(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,
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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]
§ 251.8–251.14
[Reserved]
§ 251.15 Authority for information
collection.
The Office of Management and Budget
has approved the information collection
requirements in this part under 44
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64601
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; § 252.3 also
issued under Pub. L. 99–190 making
continuing appropriations for Fiscal Year
1986, and for other purposes.
§ 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.
§ 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.
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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.
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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
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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.
§ 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
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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
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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.
§ 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
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64603
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.
§ 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.
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(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.
§ 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 § 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.
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§ 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.
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(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
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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?
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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
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§ 254.1
plan?
Who must submit a spill-response
(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
§ 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,
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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.
§ 254.2
plan?
When must I submit a response
(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 § 254.30)
after the effective date of this rule. The
Regional Supervisor may extend this
deadline upon request.
§ 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
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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 § 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.
§ 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.
§ 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
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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.
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§ 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
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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.
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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 spillresponse 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.
§ 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
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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.
§ 254.8
part?
May I appeal decisions under this
See 30 CFR part 290 for instructions
on how to appeal any order or decision
that we issue under this part.
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§ 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.
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Subpart B—Oil-Spill Response Plans
for Outer Continental Shelf Facilities
§ 254.20
Purpose.
This subpart describes the
requirements for preparing spillresponse plans for facilities located on
the OCS.
§ 254.21
plan?
How must I format my response
(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.
§ 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.
§ 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
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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 spillresponse operations center and
provisions for primary and alternate
communications systems available for
use in coordinating and directing spillresponse 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;
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(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 oilcontaminated 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.
§ 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 spillresponse equipment in accordance with
§ 254.43.
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§ 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, spillresponse 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.
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§ 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 § 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 § 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
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(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.
§ 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.
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§ 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.
§ 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 § 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
§ 254.42. You must designate a location
where you keep the records of these
exercises.
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§ 254.30
plan?
When must I revise my response
(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;
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(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
§ 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.
§ 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 spillresponse 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.
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(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.
§ 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 24hour 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
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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.
§ 254.43 Maintenance and periodic
inspection of response equipment.
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(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.
§ 254.44 Calculating response equipment
effective daily recovery capacities.
(a) You are required by § 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
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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
§ 254.45(b) and (c).
§ 254.45 Verifying the capabilities of your
response equipment.
(a) The Regional Supervisor may
require performance testing of any spillresponse 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 OilSpill 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.
§ 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
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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.
§ 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 § 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
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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
§ 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
§ 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 §§ 254.51,
254.52, and 254.53.
mstockstill on DSK4VPTVN1PROD with RULES2
§ 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 § 254.3 and contact
the appropriate regional BSEE office if
you have any questions on how to
prepare this Regional Response Plan.
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§ 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.
§ 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 § 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.
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§ 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
256.77
[Reserved]
Cancellation of leases.
Subpart L—Section 6 Leases
256.79
256.80
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Subpart M—Studies [Reserved]
§§ 256.8–256.12
Subpart N—Bonus or Royalty Credits for
Exchange of Certain Leases Offshore
Florida [Reserved]
Subpart B—Oil and Gas Leasing
Program [Reserved]
Authority: 31 U.S.C. 9701, 42 U.S.C. 6213,
43 U.S.C. 1334, Pub. L. 109–432.
Subpart C—Reports From Federal
Agencies [Reserved]
Subpart A—Outer Continental Shelf
Oil, Gas, and Sulphur Management,
General
Subpart D—Call for Information and
Nominations [Reserved]
§ 256.0
[Reserved]
§ 256.1
Purpose.
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§ 256.7
Subpart F—Lease Sales [Reserved]
Subpart H—Rentals and Royalties
[Reserved]
Subpart I—Bonding [Reserved]
Subpart J—Assignments, Transfers,
and Extensions
§§ 256.62–256.68 [Reserved]
[Reserved]
§ 256.70 Extension of lease by drilling or
well reworking operations.
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.
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§ 256.73
term.
Subpart E—Area and Identification and
Tract Size [Reserved]
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.
§§ 256.2–256.5
[Reserved]
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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.
§ 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.
§ 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.
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Effect of suspensions on lease
(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
§ 256.76
[Reserved]
§ 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
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(3) The advantages of cancellation
outweigh the advantages of continuing
such lease or permit in force.
Procedures and conditions contained in
§ 550.182 shall apply as appropriate.
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.’’
Subpart L—Section 6 Leases
§ 270.2
§ 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.
§ 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
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Sec.
270.1
270.2
270.3
270.4
270.5
270.6
270.7
Purpose.
Application of this part.
Definitions.
Discrimination prohibited.
Complaint.
Process.
Remedies.
Purpose.
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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.
§ 270.4
§ 270.5
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
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§ 270.3
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.
Authority: 43 U.S.C. 1863.
§ 270.1
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.
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
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64613
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.
§ 270.6
Process.
Whenever a Regional Director
determines on the basis of any
information, including that which may
be obtained under § 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.
§ 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.
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§ 280.27
permit?
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 E—[Reserved]
Authority: 43 U.S.C. 1334.
Subpart C—Obligations Under This
Part
Interrupted Activities
[Reserved]
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§ 280.25 When may BSEE require me to
stop activities under this part?
When may I resume activities?
The Regional Director will advise you
when you may start your permit
activities again.
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§ 280.28
May I relinquish my permit?
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
§ 282.0 Authority for information
collection.
Subpart E—[Reserved]
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.
PART 281—[RESERVED]
§ 282.1
Subpart D—[Reserved]
(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.
§ 280.26
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.
(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]
§§ 280.20–280.24
When may BSEE cancel my
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.
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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.
§ 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.
§ 282.3
Definitions.
When used in this part, the following
terms shall have the following meaning:
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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:
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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
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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.
§ 282.4
[Reserved]
§ 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
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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.
§ 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.
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§ 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.
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Subpart B—Jurisdiction and
Responsibilities of Director
been approved by the Director and the
appropriate State official.
§ 282.10 Jurisdiction and responsibilities
of Director.
§ 282.12
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.
§ 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
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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,
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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.
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§ 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;
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(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
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64617
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
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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.
mstockstill on DSK4VPTVN1PROD with RULES2
§ 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
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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)).
§ 282.15
[Reserved]
Subpart C—Obligations and
Responsibilities of Lessees
§ 282.20
[Reserved]
§ 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.
§§ 282.22–282.26
§ 282.27
[Reserved]
Conduct of operations.
(a) The lessee shall conduct all
exploration, testing, development, and
production activities and other
operations in a safe and workmanlike
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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
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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
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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
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64619
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.
§ 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:
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(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]
§ 282.29
[Reserved]
§ 282.30
[Reserved]
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
[Reserved]
§ 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.
§ 282.42
[Reserved]
Subpart E—Appeals
§ 282.50
Appeals.
See 30 CFR part 290 for instructions
on how to appeal any order or decision
that we issue under this part.
mstockstill on DSK4VPTVN1PROD with RULES2
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?
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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
§ 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.
§ 290.2
§ 282.31 Suspension of production or
other operations.
§ 282.40
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?
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.
§ 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.
§ 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.
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(2) You cannot extend the 60-day
period for payment of the processing
fee.
§ 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).
§ 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 § 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 § 290.3.
§ 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 § 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.
§ 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.
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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.
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§ 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.
§ 291.100
What is the purpose of this part?
This part:
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(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).
§ 291.101
part?
What definitions apply to this
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
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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.
§ 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
§ 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.
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§ 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.
§ 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 § 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.
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§ 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 nonfinancial impacts;
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(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.
§ 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
§ 291.108(a) or a request for reduction or
waiver of the fee under § 291.109(a); and
(c) Serve your complaint on all
persons named in the complaint. If you
make a claim under § 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.
§ 291.107
How do I answer a complaint?
(a) If you have been served a
complaint under § 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
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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 § 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.
§ 291.108
fee?
How do I pay the processing
(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: https://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.
§ 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.
§ 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
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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.
mstockstill on DSK4VPTVN1PROD with RULES2
§ 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.
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(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.
§ 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.
§ 291.113 What actions may BSEE take to
remedy denial of open and
nondiscriminatory access?
If the BSEE Director’s decision under
§ 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
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64623
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).
§ 291.114
How do I appeal to the IBLA?
Any party, except as provided in
§ 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.
§ 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.
■ 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
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570
580
581
582
585
Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations
NONDISCRIMINATION IN THE
OUTER CONTINENTAL SHELF
PROSPECTING FOR MINERALS
OTHER THAN OIL, GAS, AND
SULPHUR ON THE OUTER
CONTINENTAL SHELF
LEASING OF MINERALS OTHER
THAN OIL, GAS, AND SULPHUR IN
THE OUTER CONTINENTAL SHELF
OPERATIONS IN THE OUTER
CONTINENTAL SHELF FOR MINERALS
OTHER THAN OIL, GAS, AND
SULPHUR
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]
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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.
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Subpart A—General Provisions
[Reserved]
Subpart B—Oil and Gas, General
[Reserved]
Subpart C—[Reserved]
Subpart D—Oil and Gas, Offshore
§ 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 federallyapproved 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.
§ 519.411
subpart?
What definitions apply to this
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
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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,
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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°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.
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§ 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.
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Of the revenues allocated to a Gulf
producing State, 20 percent will be
distributed to the coastal political
subdivisions within that State.
Alabama Share = (IAL ÷ (IAL + ILA +
IMS + ITX)) × Qualified OCS
Revenues
Louisiana Share = (ILA ÷ (IAL + ILA +
IMS + ITX)) × Qualified OCS
Revenues
Mississippi Share = (IMS ÷ (IAL + ILA
+ IMS + ITX)) × Qualified OCS
Revenues
Texas Share = (ITX ÷ (IAL + ILA + IMS
+ ITX)) × 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.
§ 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?
(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.
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.
REVENUE DISTRIBUTION OF QUALIFIED
OCS REVENUES UNDER GOMESA
Recipient of qualified OCS
revenues
Percentage of
qualified OCS
revenues
(percent)
U.S. Treasury (General
Fund) ...............................
Land and Water Conservation Fund .........................
Gulf Producing States ........
Gulf Producing State Coastal Political Subdivisions ..
50
12.5
30
7.5
§ 519.413 How will the coastal political
subdivisions of Gulf producing States share
in the qualified OCS revenues?
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§ 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
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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.
Subchapter B—OFFSHORE
§ 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?
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?
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.
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.
Fees
550.125
550.126
Service fees.
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?
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§ 519.418 When will funds be disbursed to
Gulf producing States and eligible coastal
political subdivisions?
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?
(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.
Right-of-Use and Easement
550.160 When will BOEM grant me a rightof-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?
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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?
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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?
mstockstill on DSK4VPTVN1PROD with RULES2
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?
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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?
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?
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?
Well Tests and Surveys
550.1153 When must I conduct a static
bottomhole pressure survey?
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?
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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
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?
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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?
Subpart P—[Reserved]
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.
Subpart Q—[Reserved]
§ 550.102
Subpart R—[Reserved]
(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.
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 BOEMspecified 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 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
§ 550.101
Authority and applicability.
The Secretary of the Interior
(Secretary) authorized the Bureau of
Ocean Energy Management (BOEM) to
What does this part do?
TABLE—WHERE TO FIND INFORMATION FOR CONDUCTING OPERATIONS
mstockstill on DSK4VPTVN1PROD with RULES2
For information about
Refer to
(1) Applications for permit to drill .............................................................
(2) Development and Production Plans (DPP) ........................................
(3) Downhole commingling .......................................................................
(4) Exploration Plans (EP) ........................................................................
(5) Flaring .................................................................................................
(6) Gas measurement ..............................................................................
(7) Off-lease geological and geophysical permits ....................................
(8) Oil spill financial responsibility coverage ............................................
(9) Oil and gas production safety systems ..............................................
(10) Oil spill response plans .....................................................................
(11) Oil and gas well-completion operations ............................................
(12) Oil and gas well-workover operations ..............................................
(13) Decommissioning Activities ..............................................................
(14) Platforms and structures ...................................................................
(15) Pipelines and Pipeline Rights-of-Way ..............................................
(16) Sulphur operations ............................................................................
(17) Training .............................................................................................
(18) Unitization .........................................................................................
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30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
30
CFR
CFR
CFR
CFR
CFR
CFR
CFR
CFR
CFR
CFR
CFR
CFR
CFR
CFR
CFR
CFR
CFR
CFR
Sfmt 4700
250,
550,
250,
550,
250,
250,
551.
553.
250,
254.
250,
250,
250,
250,
250,
250,
250,
250,
subpart
subpart
subpart
subpart
subpart
subpart
D.
B.
K.
B.
K.
L.
subpart H.
subpart
subpart
subpart
subpart
subpart
subpart
subpart
subpart
E.
F.
Q.
I.
J and 30 CFR 550, subpart J.
P.
O.
M.
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§ 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.
§ 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.
mstockstill on DSK4VPTVN1PROD with RULES2
§ 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
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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 caseby-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
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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
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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 § 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 § 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-
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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,
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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, 3dimensional 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, 3dimensional 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 BOEMapproved 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.
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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.
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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
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64631
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
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pipeline right-of-way holder, or a State
lessee granted a right-of-use and
easement.
Performance Standards
§ 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 § 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.
§ 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
§ 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.
§ 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.
§ 550.118
[Reserved]
§ 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.
§§ 550.120—550.121
[Reserved]
§ 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.
§ 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 §§ 550.160 through
550.166 of this subpart.
Fees
§ 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.
Fee amount
(1) Change in Designation of Operator ......................................
(2) Right-of-Use and Easement for State lessee .......................
(3) [Reserved].
(4) Exploration Plan (EP) ............................................................
(5) Development and Production Plan (DPP) or Development
Operations Coordination Document (DOCD).
(6) [Reserved].
(7) Conservation Information Document ....................................
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Service—processing of the following:
$164 ..........................................................................................
$2,569 .......................................................................................
§ 550.143(d).
§ 550.165.
$3,442 for each surface location; no fee for revisions .............
$3,971 for each well proposed; no fee for revisions ................
§ 550.211(d).
§ 550.241(e).
$25,629 .....................................................................................
§ 550.296(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
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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
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30 CFR citation
submittal within 72 hours. Payment
must be made with the completed paper
or electronic application.
§ 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
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Pay.gov Web site may be accessed
through a link on the BOEM Offshore
Web site at: https://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
§ 550.130
[Reserved]
Disqualification
§ 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.
§ 550.136 How will BOEM determine if my
performance is unacceptable?
In determining if your operating
performance is unacceptable, BOEM
64633
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
§ 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 orally,
Give you an oral approval,
(b) Request approval in writing,
Give you an oral approval if quick
action is needed,
You must then confirm the oral request by sending us a written request within 72 hours.
We will send you a written approval afterward. It will include any conditions that we place on the oral approval.
§ 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.
§ 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.
mstockstill on DSK4VPTVN1PROD with RULES2
§ 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
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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 § 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.
§ 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.
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§ 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.
§ 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
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which the requirement applies are
jointly and severally responsible for
complying with the regulation.
Right-of-Use and Easement
§ 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 located in water depths of less than
200 meters;
(2) Your right-of-use and easement site
is located in water depths of 200 meters or greater;
You must pay 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 equipment associated with the platform, artificial island, installation or device.
You must pay 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 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-ofuse grant and easement.
mstockstill on DSK4VPTVN1PROD with RULES2
§ 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.
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§ 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 rightof-use and easement is situated must
continue to recognize the right-of-use
and easement for the purpose that the
grant specifies.
§ 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-ofuse 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.
§ 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-
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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.
§ 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 § 550.125; and
(b) The first year’s rental as specified
in § 550.160(g).
§ 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-ofuse 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
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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 rightof-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?
If the Secretary cancels your lease
under this part or under 30 CFR part
556, you are entitled to compensation
under § 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.
mstockstill on DSK4VPTVN1PROD with RULES2
§ 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.
§ 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
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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.
§ 550.184 What is the amount of
compensation for lease cancellation?
When the Secretary cancels a lease
under §§ 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.
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64635
§ 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
§ 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 computergenerated 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 § 550.197
or otherwise exempt from public
disclosure under law or regulation.
§§ 550.187–550.193
[Reserved]
§ 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
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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.
§ 550.195
[Reserved]
§ 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.
§ 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:
On form . . .
Data and information not immediately available are . . .
Excepted data will be made available . . .
(1) [Reserved].
(2) [Reserved].
(3) [Reserved].
(4) [Reserved].
(5) [Reserved].
(6) BOEM–0127, Sensitive Reservoir Information Report,
(7) [Reserved].
(8) [Reserved].
(9) BOEM–0137 OCS Plan Information,
Items 124 through 168,
2 years after the effective date of the Sensitive Reservoir Information
Report.
Items providing the bottomhole location, true vertical depth, and
measured depth of wells,
All items,
When the well goes on production or according to the table in paragraph (b) of this section, whichever is earlier.
(10)
BOEM–0140,
Bottomhole
Pressure Survey Report,
(b) BOEM will release lease and
permit data and information that you
submit and BOEM retains, but that are
2 years after the date of the survey.
not normally submitted on BOEM
forms, according to the following table:
mstockstill on DSK4VPTVN1PROD with RULES2
If . . .
BOEM will release . . .
At this time . . .
Special provisions . . .
(1) The Director determines that
data and information are needed
for specific scientific or research
purposes for the Government,
Geophysical data, Geological data
Interpreted G&G information,
Processed G&G information,
Analyzed geological information,
At any time,
BOEM will release data and information only if release would further the National interest without unduly damaging the competitive position of the lessee.
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64637
BOEM will release . . .
At this time . . .
Special provisions . . .
(2) Data or information is collected
with high-resolution systems
(e.g.,
bathymetry,
side-scan
sonar, subbottom profiler, and
magnetometer) to comply with
safety or environmental protection requirements,
Geophysical data, Geological
data, Interpreted G&G information, Processed geological information, Analyzed geological information,
60 days after BOEM receives the
data or information, if the Regional Supervisor deems it necessary,
(3) Your lease is no longer in effect,
Geophysical data, Geological
data, Processed G&G information Interpreted G&G information, Analyzed geological information,
When your lease terminates,
(4) Your lease is still in effect,
Geophysical data, Processed
geophysical information, Interpreted G&G information,
10 years after you submit the
data and information,
(5) Your lease is still in effect and
within the primary term specified
in the lease,
Geological data, Analyzed geological information,
2 years after the required submittal date or 60 days after a
lease sale if any portion of an
offered lease is within 50 miles
of a well, whichever is later,
(6) Your lease is in effect and beyond the primary term specified
in the lease,
(7) Data or information is submitted on well operations,
Geological data, Analyzed geological information,
2 years after the required submittal date,
BOEM will release the data and
information earlier than 60 days
if the Regional Supervisor determines it is needed by affected States to make decisions
under subpart B. The Regional
Supervisor will reconsider earlier release if you satisfy him/
her that it would unduly damage your competitive position.
This release time applies only if
the provisions in this table governing high-resolution systems
and the provisions in § 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.
This release time applies only if
the provisions in this table governing high-resolution systems
and the provisions in § 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.
These release times apply only if
the provisions in this table governing high-resolution systems
and the provisions in § 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.
None.
Descriptions of downhole locations, operations, and equipment,
(8) Data and information are obtained from beneath unleased
land as a result of a well deviation that has not been approved by the Regional Supervisor,
(9) Except for high-resolution data
and information released under
paragraph (b)(2) of this section
data and information acquired by
a permit under 30 CFR part 551
are submitted by a lessee under
part 550, 30 CFR part 203, or
30 CFR part 250,
mstockstill on DSK4VPTVN1PROD with RULES2
If . . .
Any data or information obtained,
When the well goes on production
or when geological data is released
according
to
§§ 550.197(b)(5) and (b)(6),
whichever occurs earlier,
At any time,
G&G data, analyzed geological information, processed and interpreted G&G information,
(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]
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Geological data and information:
10 years after BOEM issues the
permit; Geophysical data: 50
years after BOEM issues the
permit; Geophysical information: 25 years after BOEM
issues the permit,
(2) [Reserved]
(3) [Reserved]
(4) Promote operational safety;
(5) Protect the environment; or
(6) Make field determinations.
(7) [Reserved]
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Directional survey data may be
released earlier to the owner of
an adjacent lease according to
30 CFR 250 subpart D.
None.
None.
References
§ 550.198
[Reserved]
§ 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
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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 § 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 (OMB Control No.)
Reasons for collecting information and how used
(1) Subpart A, General (1010–0114), including Forms BOEM–1123,
Designation of Operator and BOEM–1832, Notification of Incidents of
Noncompliance.
To inform BOEM of actions taken to comply with general 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 exploration, development, and production on
OCS leases. To support the unproved and proved reserve estimation, resource assessment, and fair market value determinations.
To inform BOEM, States, and the public of planned exploration, 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.
To inform BOEM of measures to be taken to prevent air pollution. To
ensure that appropriate measures are taken to prevent air pollution.
To provide BOEM with information regarding the design, installation,
and operation of pipelines on the OCS. To ensure that pipeline operations are safe and protect the human, marine, and coastal environment.
To inform BOEM of production rates for hydrocarbons produced on the
OCS. To ensure economic maximization of ultimate hydrocarbon recovery.
The requirements in subpart N are exempt from the Paperwork Reduction Act of 1995 according to 5 CFR 1320.4.
(2) Subpart B, Exploration and Development and Production Plans
(1010–0151), including Forms BOEM–0137, OCS Plan Information
Form; BOEM–0138, EP Air Quality Screening Checklist; BOEM–
0139, DOCD Air Quality Screening Checklist; BOEM–0141, ROV
Survey Report Form; and BOEM–0142, Environmental Impact Analysis Worksheet.
(3) Subpart C, Pollution Prevention and Control (1010–0057) ................
(4) Subpart J, Pipelines and Pipeline Rights-of-Way (1010–0050), including Form BOEM–2030, Outer Continental Shelf (OCS) Pipeline
Right-of-Way Grant Bond.
(5) Subpart K, Oil and Gas Production Rates (1010–0041), including
Forms BOEM–0127, Sensitive Reservoir Information Report and
BOEM–0140, Bottomhole Pressure Survey Report.
(6) Subpart N, Remedies and Penalties ..................................................
Subpart B—Plans and Information
General Information
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§ 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.
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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 §§ 550.232(d) and 550.267(d)).
Modification means a change required
by the Regional Supervisor to an EP,
DPP, or DOCD (see § 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 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
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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 §§ 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 § 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 § 550.283(b)).
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§ 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
64639
plans and documents may cover one or
more leases or units.
You must submit a(n) . . .
Before you . . .
(1) Exploration Plan (EP),
(2) Development and Production Plan (DPP),
Conduct any exploration activities on a lease or unit.
Conduct any development and production activities on a lease or unit in any OCS area other
than the Western Gulf of Mexico.
Conduct any development and production activities on a lease or unit in the Western GOM.
(3) Development Operations Coordination Document (DOCD),
(4) BSEE approved Deepwater Operations Plan
(DWOP),
(5) Conservation Information Document (CID),
(6) EP, DPP, or DOCD,
(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.
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§ 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;
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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.
Commence production from development projects in water depths greater than 1,312 feet (400
meters).
Conduct geological or geophysical (G&G) exploration or a development G&G activity (see definitions under § 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 § 550.209, determines that an EP,
DPP, or DOCD is necessary.
(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.
§ 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.
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§§ 550.204
§ 550.206
DOCD?
550.205 [Reserved]
How do I submit the EP, DPP, or
(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
§ 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:
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(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.
§ 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
§ 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
§ 550.207(b) and (c)) in addition to those
listed in § 550.207(a); and
(2) Notify other users of the OCS
before you conduct any ancillary
activity.
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§ 550.209 What is the BOEM review
process for the notice?
The Regional Supervisor will review
any notice required under § 550.208(a)
and (b)(1) to ensure that your ancillary
activity complies with the performance
standards listed in § 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.
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§ 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
§ 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
§ 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
§ 550.197(b).
Contents of Exploration Plans (EP)
§ 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 § 550.105(3)).
(d) Service fee. You must include
payment of the service fee listed in
§ 550.125.
§ 550.212 What information must
accompany the EP?
The following information must
accompany your EP:
(a) General information required by
§ 550.213;
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(b) Geological and geophysical (G&G)
information required by § 550.214;
(c) Hydrogen sulfide information
required by § 550.215;
(d) Biological, physical, and
socioeconomic information required by
§ 550.216;
(e) Solid and liquid wastes and
discharges information and cooling
water intake information required by
§ 550.217;
(f) Air emissions information required
by § 550.218;
(g) Oil and hazardous substance spills
information required by § 550.219;
(h) Alaska planning information
required by § 550.220;
(i) Environmental monitoring
information required by § 550.221;
(j) Lease stipulations information
required by § 550.222;
(k) Mitigation measures information
required by § 550.223;
(l) Support vessels and aircraft
information required by § 550.224;
(m) Onshore support facilities
information required by § 550.225;
(n) Coastal zone management
information required by § 550.226;
(o) Environmental impact analysis
information required by § 550.227; and
(p) Administrative information
required by § 550.228.
§ 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 § 550.200) you will use to carry
out your proposed exploration
activities. In the public information
copies of your EP, you may exclude any
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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 (email address, if available), and
telephone number of the person with
whom the Regional Supervisor and any
affected State(s) can communicate about
your EP.
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§ 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 hydrocarbonbearing reservoir showing the locations
of proposed wells.
(c) Two-dimensional (2–D) or threedimensional (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
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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.
§ 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
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64641
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.
§ 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. Sitespecific meteorological, physical
oceanographic, geotechnical reports, or
archaeological reports (if required under
§ 550.194).
(c) Socioeconomic study reports.
Socioeconomic information regarding
your proposed exploration activities.
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§ 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.
§ 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
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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 § 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 § 550.303(d).
When BOEM requires air quality
modeling, you must use the guidelines
in Appendix W of 40 CFR part 51 with
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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 § 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.
§ 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.
§ 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
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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.
§ 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.
§ 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.
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§ 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
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(2) Marine mammals, as appropriate,
if you have not already received
authorization for incidental take as may
be necessary under the MMPA.
§ 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 § 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 § 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.
§ 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.
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(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 § 550.217)
and the types and quantities of such
wastes.
§ 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).
§ 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
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(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;
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(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.
§ 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
§ 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
§ 550.212), fulfills requirements and is
sufficiently accurate;
(2) You have provided all needed
additional information (see
§ 550.201(b)); and
(3) You have provided the required
number of copies (see § 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
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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.
§ 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
§ 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 deemedsubmitted 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 § 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 § 550.231.
§ 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 § 550.231, or
receives the last amendment to your
proposed EP, whichever occurs later.
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(b) BOEM decision. By the deadline in
paragraph (a) of this section, the
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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,
(2) Require you to modify
your proposed EP,
The Regional Supervisor finds that it is inconsistent
with the lease, the Act, the regulations prescribed
under the Act, or other Federal laws,
(3) Disapprove your EP,
Your proposed activities would probably cause serious
harm or damage to life (including fish or other aquatic life); property; any mineral (in areas leased or not
leased); the National security or defense; or the marine, coastal, or human environment; and you cannot
modify your proposed activities to avoid such condition(s),
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.
The Regional Supervisor will notify you in writing of the
decision and describe the modifications you must
make to your proposed EP to ensure it complies with
all applicable requirements.
(i) The Regional Supervisor will notify you in writing of
the decision and describe the reason(s) for disapproving your EP.
(ii) BOEM may cancel your lease and compensate you
under 43 U.S.C. 1334(a)(2)(C) and the implementing
regulations in §§ 550.182, 550.184, and 550.185 and
30 CFR 556.77.
§ 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 § 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
§ 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 § 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.
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§ 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 § 550.233(a)
or § 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.
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(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)
§ 550.241
include?
What must the DPP or DOCD
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
§ 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
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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
§ 550.105).
(d) Production facilities. A description
of the production platforms, satellite
structures, subsea wellheads and
manifolds, lease term pipelines (see
definition at § 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
§ 550.105).
(e) Service fee. You must include
payment of the service fee listed in
§ 550.125.
§ 550.242 What information must
accompany the DPP or DOCD?
The following information must
accompany your DPP or DOCD.
(a) General information required by
§ 550.243;
(b) G&G information required by
§ 550.244;
(c) Hydrogen sulfide information
required by § 550.245;
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(d) Mineral resource conservation
information required by § 550.246;
(e) Biological, physical, and
socioeconomic information required by
§ 550.247;
(f) Solid and liquid wastes and
discharges information and cooling
water intake information required by
§ 550.248;
(g) Air emissions information required
by § 550.249;
(h) Oil and hazardous substance spills
information required by § 550.250;
(i) Alaska planning information
required by § 550.251;
(j) Environmental monitoring
information required by § 550.252;
(k) Lease stipulations information
required by § 550.253;
(l) Mitigation measures information
required by § 550.254;
(m) Decommissioning information
required by § 550.255;
(n) Related facilities and operations
information required by § 550.256;
(o) Support vessels and aircraft
information required by § 550.257;
(p) Onshore support facilities
information required by § 550.258;
(q) Sulphur operations information
required by § 550.259;
(r) Coastal zone management
information required by § 550.260;
(s) Environmental impact analysis
information required by § 550.261; and
(t) Administrative information
required by § 550.262.
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§ 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,
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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 § 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.
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§ 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 threedimensional (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.
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(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.
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§ 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.
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§ 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.
§ 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. Sitespecific meteorological, physical
oceanographic, geotechnical reports, or
archaeological reports (if required under
§ 550.194).
(c) Socioeconomic study reports.
Socioeconomic information related to
your proposed development and
production activities.
§ 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:
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(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.
§ 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),
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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.
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(e) Non-exempt facilities. A
description of how you will comply
with § 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 § 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 § 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.
§ 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
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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.
§ 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.
§ 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.
§ 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
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to your proposed development and
production activities must accompany
your DPP or DOCD.
§ 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.
§ 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.
mstockstill on DSK4VPTVN1PROD with RULES2
§ 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;
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(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.
§ 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 § 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 § 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.
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§ 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-ofway 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 § 550.248(a)) and the types and
quantities of such wastes.
§ 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
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platforms, and production facilities, and
to protect the environment.
§ 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).
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§ 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,
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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.
§ 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
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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
§ 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 § 550.242), fulfills
requirements and is sufficiently
accurate;
(2) You have provided all needed
additional information (see
§ 550.201(b)); and
(3) You have provided the required
number of copies (see § 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.
§ 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 § 550.266, the Regional
Supervisor will use receipted mail or
alternative method to send a public
information copy of the DPP or DOCD
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and its accompanying information to the
following:
(1) The Governor of each affected
State. The Governor has 60 calendar
days after receiving your deemedsubmitted 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 § 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 § 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 § 550.266.
§ 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.
§ 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
64651
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.
§ 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 deemedsubmitted 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
§ 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:
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The regional supervisor will . . .
If . . .
And then . . .
(1) Approve your DPP or DOCD,
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.
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The regional supervisor will . . .
If . . .
And then . . .
(2) Require you to modify your proposed DPP or DOCD,
It fails to make adequate provisions for safety, environmental
protection, or conservation of
natural resources or otherwise
does not comply with the lease,
the Act, the regulations prescribed under the Act, or other
Federal laws,
Any of the reasons in § 550.271
apply,
The Regional Supervisor will notify you in writing of the decision and
describe the modifications you must make to your proposed DPP
or DOCD to ensure it complies with all applicable requirements.
(3) Disapprove your DPP or DOCD,
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§ 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 § 550.273(b).
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(i) The Regional Supervisor will notify 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
§§ 550.183 through 550.185 and 30 CFR 556.77.
(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.
§ 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
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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.
§ 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 § 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 § 550.270(b)(3), and
except as provided in § 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 § 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.
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Post-Approval Requirements for the EP,
DPP, and DOCD
§ 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 § 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.
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§ 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
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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.
§ 550.282 Do I have to conduct postapproval 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.
§ 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:
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64653
(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.
§ 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.
§ 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
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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 §§ 550.231 through
550.235 for EPs and §§ 550.266 through
550.273 for DPPs and DOCDs.
§§ 550.286–550.295
[Reserved]
Conservation Information Documents
(CID)
§ 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 § 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.
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§ 550.297
contain?
What information must a CID
(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
§ 550.115 or § 550.116:
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(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 inplace 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
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(16) Any other appropriate data you
used in performing your reservoir
evaluations and preparing your
reservoir development strategies.
§ 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 150calendar-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 hydrocarbonbearing 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.
§ 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
§§ 550.300–550.301
§ 550.302
quality.
[Reserved]
Definitions concerning air
For purposes of §§ 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
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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.
§ 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 § 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 § 550.218 or
§ 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
64655
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 annualtotal amount of emissions from the
facility for each air pollutant calculated
in § 550.249(a) or § 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
[μg/m3]
Averaging time (hours)
Air pollutant
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Annual
SO2 .......................................................................................
TSP ......................................................................................
NO2 ......................................................................................
CO ........................................................................................
(f) Significance determinations. (1)
The projected emissions of any air
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1
1
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1
........................
5
5
........................
........................
........................
........................
........................
500
25
........................
........................
........................
........................
........................
........................
2,000
pollutant other than VOC from any
facility which result in an onshore
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ambient air concentration above the
significance level determined under
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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
[μg/m3]
Averaging times
Air pollutant
Annual mean 1
Class I:
TSP
SO2
Class II:
TSP
SO2
Class III:
TSP
SO2
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1 For
24-hour
maximum
3-hour
maximum
.......................................................................................................................................
.......................................................................................................................................
5
2
10
5
........................
25
.......................................................................................................................................
.......................................................................................................................................
19
20
37
91
........................
512
.......................................................................................................................................
.......................................................................................................................................
37
40
75
182
........................
700
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
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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
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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
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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.
§ 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 § 550.218 or
§ 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
64657
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
§ 550.218(a) or § 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
[μG/M3]
Averaging time (hours)
Air pollutant
Annual
mstockstill on DSK4VPTVN1PROD with RULES2
SO2 .......................................................................................
TSP ......................................................................................
NO2 ......................................................................................
CO ........................................................................................
(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
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1
........................
5
5
........................
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........................
........................
........................
500
25
........................
........................
........................
........................
........................
........................
2,000
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
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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
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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
§ 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
§ 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.
Annual static bottomhole pressure surveys in a sufficient number of key wells to establish an
average reservoir pressure. The Regional Supervisor may require that bottomhole pressure
surveys be performed on specific wells.
mstockstill on DSK4VPTVN1PROD with RULES2
(2) A reservoir with three or more producing
completions,
(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.
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Classifying Reservoirs
§ 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
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Fmt 4701
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submit a request to the Regional
Supervisor to reclassify the reservoir.
You must include supporting
information, as listed in the table in
§ 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
§ 550.1167, with your request.
§ 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 §§ 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 § 550.1167. You
must submit this information:
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(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
(§ 550.1167(a)(2)) or previously
submitted well logs (§ 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 § 550.1154(c).
Other Requirements
§ 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
§ 550.1167, 30 CFR 250.1167, and any
additional information required by the
BSEE Regional Supervisor.
(c) [Reserved].
§ 550.1166 What additional reporting is
required for developments in the Alaska
OCS Region?
(b) [Reserved]
(c) Every time you are required to
submit Form BOEM–0127 under
§ 550.1155, you must request an MER
for each producing sensitive reservoir in
the Alaska OCS Region, unless
otherwise instructed by the Regional
Supervisor.
§ 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:
(a) [Reserved]
SRI BOEM–0127
(2 copies)
mstockstill on DSK4VPTVN1PROD with RULES2
(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 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 applicable ................................................
(c) Logs:
(1) Well log sections with tops and bottoms of the reservoir(s) and proposed or existing perforations .............................................................................................................
(2) Structural cross-sections showing the subject well and nearby wells .......................
(d) Engineering data:
(1) Estimated recoverable reserves for 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 proposed conditions ......................................
(3) The drive mechanism of each reservoir .....................................................................
(4) Pressure data, by date, and whether they are estimated or measured ....................
(5) Production data and decline curve analysis indicative of the reservoir performance
(6) Reservoir simulation with the reservoir parameters used, history matches, and prediction runs (include proposed development scenario) ................................................
(e) General information:
(1) Detailed economic analysis ........................................................................................
(2) Reservoir name and whether or not it is competitive as defined under § 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 ......................................................................................
(5) Explanation of why the proposed completion scenario will maximize ultimate recovery .................................................................................................................................
(6) List of all wells in subject reservoirs that have ever produced or been used for injection ............................................................................................................................
Reservoir reclassification
........................................
........................................
√
√
*
........................................
*
........................................
........................................
........................................
........................................
√
√
........................................
√
√
√
√
........................................
........................................
........................................
........................................
√
√
√
........................................
*
√
√
........................................
........................................
........................................
√
........................................
........................................
........................................
√
√ 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
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appropriate payment of the service
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fee(s) listed in § 550.125, according to
the instructions in § 550.126.
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Outer Continental Shelf Lands Act Civil
Penalties
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.
§ 550.1400 How does BOEM begin the civil
penalty process?
§ 550.1401
This subpart explains BOEM’s civil
penalty procedures whenever a lessee,
The following table is an index of the
sections in this subpart:
Subpart L—[Reserved]
Subpart M—[Reserved]
Subpart N—Outer Continental Shelf
Civil Penalties
Index table.
(a) Definitions ....................................................................................................................................................................................
(b) What is the maximum civil penalty? ...........................................................................................................................................
(c) Which violations will BOEM review for potential civil penalties? ................................................................................................
(d) When is a case file developed? ..................................................................................................................................................
(e) When will BOEM notify me and provide penalty information? ...................................................................................................
(f) How do I respond to the letter of notification? ............................................................................................................................
(g) When will I be notified of the Reviewing Officer’s decision? ......................................................................................................
(h) What are my appeal rights? ........................................................................................................................................................
§ 550.1402
Definitions.
§ 550.1405
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.
§ 550.1403
penalty?
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.
§ 550.1407 How do I respond to the letter
of notification?
§ 550.1404 Which violations will BOEM
review for potential civil penalties?
mstockstill on DSK4VPTVN1PROD with RULES2
§ 550.1406 When will BOEM notify me and
provide penalty information?
What is the maximum civil
The maximum civil penalty is
$40,000 per day per violation.
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.
VerDate Mar<15>2010
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 § 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.
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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.
§ 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
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§ 550.1402
§ 550.1403
§ 550.1404
§ 550.1405
§ 550.1406
§ 550.1407
§ 550.1408
§ 550.1409
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.
§ 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 leasespecific/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 § 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 § 556.56.
(d) If you do not either pay the
penalty or file a timely appeal, BOEM
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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
§ 550.1450
subpart?
What definitions apply to this
The terms used in this subpart have
the same meaning as in 30 U.S.C. 1702.
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?
(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.
§ 550.1452
What if I correct the violation?
mstockstill on DSK4VPTVN1PROD with RULES2
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).
§ 550.1453
violation?
What if I do not correct the
(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
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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.
§ 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.
§ 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
§ 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
§§ 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).
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§ 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 § 550.1454. If you did not
request a hearing on the record on the
Notice of Noncompliance under
§ 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
§ 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]
§ 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.
§ 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,
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Arlington, Virginia 22203. You may do
this regardless of whether you correct
the violations identified in the Notice of
Noncompliance.
§ 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
§ 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
§§ 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).
§ 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 § 550.1462. If you
did not request a hearing on the record
on the Notice of Noncompliance under
§ 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.
mstockstill on DSK4VPTVN1PROD with RULES2
General Provisions
§ 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.
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§ 550.1471 Does the penalty affect whether
I owe interest?
If you do not pay the penalty by the
date required under § 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.
§ 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 §§ 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.
§ 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.
§ 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.
§ 550.1475
When must I pay the penalty?
(a) You must pay the amount of the
Notice of Civil Penalty issued under
§§ 550.1453 or 550.1461, if you do not
request a hearing on the record under
§§ 550.1454, 550.1456, 550.1462, or
550.1464
(b) If you request a hearing on the
record under §§ 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
§ 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 §§ 550.1454,
550.1456, 550.1462, or 550.1464;
(2) You received an Administrative
Law Judge’s decision under § 550.1472,
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if you obtained a stay of the accrual of
penalties pending the hearing on the
record under § 550.1455(b) or
§ 550.1463(b) and did not appeal the
Administrative Law Judge’s
determination to the IBLA under
§ 550.1473;
(3) You received an IBLA decision
under § 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 § 550.1477.
§ 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.
§ 550.1477
penalty?
How may BOEM collect the
(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 § 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 § 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
§ 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 § 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.
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Bonding Requirements
Financial Solvency Requirements
§ 550.1490 What standards must my
BOEM-specified surety instrument meet?
§ 550.1495
solvency?
(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.
(a) To demonstrate financial solvency
under this part, you must submit an
audited consolidated balance sheet, and,
if requested by the BOEM bondapproving 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.
mstockstill on DSK4VPTVN1PROD with RULES2
§ 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 BOEMspecified 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.
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How do I demonstrate financial
§ 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 §§ 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 §§ 550.1490 and 550.1491 for all
orders you have appealed is less than
$300 million, you must submit the
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64663
following to BOEM by one of the
methods in §§ 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 §§ 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 businessinformation 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
§§ 550.1490 and 550.1491;
(ii) If our bond-approving officer
determines that the businessinformation 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
§§ 550.1490 and 550.1491 or pay the
obligation.
§ 550.1497 When will BOEM monitor my
financial solvency?
(a) If you are presumptively
financially solvent under § 550.1496(b),
BOEM will determine your net worth as
described under §§ 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
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active appeals and each time you appeal
a new order.
(b) If you ask us to consult a businessinformation or credit-reporting service
or program under § 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 §§ 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.
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Authority: 31 U.S.C. 9701, 43 U.S.C. 1334.
§ 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
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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.
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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
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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:
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(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 inhouse 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
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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.
§ 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.
§ 551.3
part.
Authority and applicability of this
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.
§ 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
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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 30day Notice, you must provide oral
notification and followup in writing.
You must also inform BOEM in writing
when you conclude your work.
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§ 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;
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(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.
§ 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-ofway, 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
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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.
§ 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 § 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;
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(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.
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(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
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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
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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 costsharing 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.
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(4) Your bond must be on a form
approved by the Associate Director for
BOEM.
§ 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.
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§ 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.
§ 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
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(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.
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§ 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;
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(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.
§ 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 inhouse interpretation by the permittee, or
become available commercially to third
parties via sale, trade, license
agreement, or other means.
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(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
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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.
§ 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 §§ 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.
§ 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 release them to the public . . .
(i) Geological data and information,
(ii) Geophysical data,
(iii) Geophysical information processed or reprocessed less than 20
years after BOEM issued the germane permit,
(iv) Geophysical information processed or reprocessed 20 or more
years after BOEM issued the germane permit,
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If you or a third party submit and BOEM retains . . .
10 years after BOEM issued the permit.
50 years after BOEM issued the permit.
25 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
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25 years after BOEM issued the permit; or, if you or a third 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.
§ 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;
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(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
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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 § 551.12 and
reimbursement criteria identified under
§ 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
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and information under § 551.11 or
§ 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
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64671
(ii) The regulations at 30 CFR parts
550, 551, and 552.
§ 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 § 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.
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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; § 252.3 also
issued under Pub. L. 99–190 making
continuing appropriations for Fiscal Year
1986, and for other purposes.
§ 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.
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§ 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;
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(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
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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
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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.
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§ 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
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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
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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.
§ 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
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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.
§ 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.
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§ 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
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and Geophysical Explorations of the
Outer Continental Shelf).
(b) Except as provided in § 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.
§ 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
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(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
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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.
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?
PART 553—OIL SPILL FINANCIAL
RESPONSIBILITY FOR OFFSHORE
FACILITIES
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 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?
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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 selfinsurance 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 selfinsurance 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?
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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
§ 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.
§ 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
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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 federallyrecognized 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 1:63,360scale 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.
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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
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(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.
§ 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
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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
§ 553.10
cover?
What facilities does this part
(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.
§ 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.
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(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.
§ 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 § 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.
§ 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,
More than one COF,
The amount of OSFR that applies to the 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
amount of
OSFR
COF worst case oil-spill discharge volume
Over
Over
Over
Over
1,000 bbls but not more than 35,000 bbls .................................................................................................................................
35,000 but not more than 70,000 bbls .......................................................................................................................................
70,000 but not more than 105,000 bbls .....................................................................................................................................
105,000 bbls ...............................................................................................................................................................................
$35,000,000
70,000,000
105,000,000
150,000,000
(2) For a COF not located in the OCS
you must demonstrate OSFR in
accordance with the following table:
Applicable
amount of
OSFR
COF worst case oil-spill discharge volume
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Over
Over
Over
Over
Over
1,000 bbls but not more than 10,000 bbls .................................................................................................................................
10,000 but not more than 35,000 bbls .......................................................................................................................................
35,000 but not more than 70,000 bbls .......................................................................................................................................
70,000 but not more than 105,000 bbls .....................................................................................................................................
105,000 bbls ...............................................................................................................................................................................
(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
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(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.
§ 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 § 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
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$10,000,000
35,000,000
70,000,000
105,000,000
150,000,000
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.
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§ 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 § 553.60, then
you must give the claimant a written
explanation for your denial.
Subpart C—Methods for
Demonstrating OSFR
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§ 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 §§ 553.21
through 553.28;
(b) Insurance under § 553.29;
(c) An indemnity under § 553.30;
(d) A surety bond under § 553.31; or
(e) An alternative method the Director
approves under § 553.32.
§ 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
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demonstrate OSFR, you must annually
pass either a net worth test under
§ 553.25 or an unencumbered net asset
test under § 553.28.
(b) To establish the amount of selfinsurance allowed, you must submit
evidence of your net worth under
§ 553.23 or evidence of your
unencumbered assets under § 553.26.
(c) You must identify a U.S. agent for
service of process.
§ 553.22 How do I apply to use selfinsurance 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.
§ 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).
§ 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
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(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.
§ 553.25 What financial test procedures
must I use to determine the amount of selfinsurance 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.
§ 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 § 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
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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.
§ 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 § 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.
§ 553.28 What financial test procedures
must I use to evaluate the amount of selfinsurance 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.
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§ 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 § 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
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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 § 553.13;
(2) No more than one insurance
certificate may be used to cover each
OSFR layer specified in § 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.
64679
(1) Includes all the information
required by § 553.41; and
(2) Does not exceed the amounts
calculated using the net worth or
unencumbered assets tests specified
under §§ 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.
§ 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 § 553.41.
§ 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 § 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
§ 553.30 How can I use an indemnity as
OSFR evidence?
§ 553.40 What OSFR evidence must I
submit to BOEM?
(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:
(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
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demonstrate OSFR (Form BOEM–1018,
Form BOEM–1019, Form BOEM–1020).
Forms are available from the address
listed in § 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 § 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.
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§ 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 § 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
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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.
§ 553.42
COFs?
How can I amend my list of
(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).
§ 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.
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§ 553.44
[Reserved]
§ 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
§ 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 § 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.
§ 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
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found at 30 CFR part 550, subpart N.
You may obtain a copy of the penalty
schedule from BOEM at the address in
§ 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
§ 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
64681
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 petition in bankruptcy under 11
U.S.C. chapter 7 or 11,
(i) Present your claim to any of the responsible 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.
(i) Pursue any of the remedies in items (1)(i) 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.
(2) An assertion of insolvency or petition in bankruptcy under 11 U.S.C.
chapter 7 or 11,
(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 § 553.45. You must include any
information you have regarding the
existence or identity of possible
guarantors.
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§ 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., oilspill 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.
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§ 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–
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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
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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
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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;
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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.
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556.44
556.46
556.47
556.49
556.50
Bids disqualified.
Submission of bids.
Award of leases.
Lease form.
Dating of leases.
Subpart A—Outer Continental Shelf
Oil, Gas, and Sulphur Management,
General
§ 556.0 Authority for information
collection.
Subpart H—Rentals and Royalties
[Reserved]
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.
(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.
Subpart K—Termination of Leases
§ 556.1
556.76 Relinquishment of leases or parts of
leases.
556.77 Cancellation of leases.
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.
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
Subpart L—Section 6 Leases
556.79
556.80
Effect of regulations on lease.
Leases of other minerals.
Subpart M—Studies
556.82
Environmental studies.
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Subpart N—Bonus or Royalty Credits for
Exchange of Certain Leases Offshore
Florida
§ 556.2
Purpose.
Policy.
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?
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.
Appendix to Part 556—Oil and Gas Cash
Bonus Bid
§ 556.4
Authority: 31 U.S.C. 9701, 42 U.S.C. 6213,
43 U.S.C. 1334, Pub. L. 109–432.
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Authority.
The Outer Continental Shelf Lands
Act (OCSLA) (43 U.S.C. 1331 et seq.)
authorizes the Secretary of the Interior
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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 rightsof-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.
§ 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
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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
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(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.
§ 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
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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.
§ 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.
§ 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
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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.
§ 556.11
Helium.
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(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.
§ 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 § 556.22.
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(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
§ 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
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64685
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.
§ 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.
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(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.
§ 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 §§ 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.
§ 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
§ 556.16 of this part.
Subpart C—Reports From Federal
Agencies
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§ 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
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the total environment or other uses of
the area.
Subpart D—Call for Information and
Nominations
§ 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.
§ 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
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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
§ 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
§ 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.
§ 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.
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Subpart F—Lease Sales
§ 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.
§ 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.
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§ 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,
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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
§ 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
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lease assignments if your operating
performance is unacceptable according
to 30 CFR 550.135.
§ 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.
§ 556.38
Joint bidding provisions.
§ 556.40
Definitions.
The following definitions apply to
§§ 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 § 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,
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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
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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.
§ 556.41
Joint bidding requirements.
(a) Any person who submits a joint
bid for any oil and gas lease during a 6month 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
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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 § 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
§ 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 § 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
§§ 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
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exploration and development will not
occur on such lands unless the
exemption is granted.
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§ 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, collateraltrust 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 § 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
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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 °F.
(e)(1) For purposes of computing
production of natural gas under § 556.41
of this part, chargeability under this
section, and reporting under § 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 § 556.41 of this part,
chargeability under § 556.46(g) of this
part, 1.454 barrels of natural gas liquids
at 60 °F shall equal one barrel of crude
oil.
§ 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 § 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
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64689
production when required to do so
under § 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 § 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.
§ 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
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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
§ 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 § 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
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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.
§ 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 § 556.35(b) of this
part, or disqualified under § 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.
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(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 § 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.
§ 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.
§ 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.
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Subpart H—Rentals and Royalties
[Reserved]
Subpart I—Bonding
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§ 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 § 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 § 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
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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.
§ 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
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(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
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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 §§ 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
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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.
§ 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 § 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:
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(1) A surety bond;
(2) Treasury securities as provided in
§ 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.
§ 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 §§ 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.
§ 556.56 Lease-specific abandonment
accounts.
(a) The Regional Director may
authorize you to establish a leasespecific abandonment account in a
federally insured institution in lieu of
the bond required under § 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 leasespecific 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.
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(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.
§ 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 thirdparty guarantee instead of an additional
bond under § 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 thirdparty guarantor (guarantor) has been in
continuous operation as a business
entity where:
64693
(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 recently completed fiscal year,
Include a report by an 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.
Your guarantor’s financial officer certifies to be correct.
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(ii) Financial statements for completed quarters in the current fiscal
year,
(iii) Additional information as requested by the Regional Director,
(d) Provisions required in all thirdparty 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
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Your guarantor’s financial officer certifies to be correct.
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;
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(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
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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
§ 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.
§ 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
§ 556.52(a) or under § 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 § 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:
The period of liability will end
Your bond will be cancelled . . .
(1) Base bonds submitted under § 556.52(a),
§ 556.53(a), or (b),
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For the following type of bond
When the Regional Director determines that
you have met all of your obligations under
the lease,
(2) Supplemental
§ 556.53(d),
When the Regional Director determines that
you have met all your obligations covered
by the supplemental bond,
Seven years after the termination of the
lease, 6 years after completion of all bonded 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.
When you meet your bonded obligations, unless the Regional Director:
bonds
submitted
under
(i) Determines that the future potential liability
resulting from any undetected problems is
greater than the amount of the base bond;
and
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For the following type of bond
The period of liability will end
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Your bond will be cancelled . . .
(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.
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§ 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,
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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.
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Subpart J—Assignments, Transfers,
and Extensions
§ 556.62
lease.
Assignment of lease or interest in
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
§ 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 § 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
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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.
§ 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
(1) Record Title/Operating Rights (Transfer) ........................................................................................................
(2) Non-required Document 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.
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§ 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 § 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.
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(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 § 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 § 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 § 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 §§ 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
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$186
27
30 CFR citation
§ 556.64
§ 556.64
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
§ 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:
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(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.
§ 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.
§ 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.
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§ 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
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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.
§ 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.
§ 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.
§ 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
§ 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
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64697
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.
§ 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
§ 550.182 shall apply as appropriate.
Subpart L—Section 6 Leases
§ 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.
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(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.
§ 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
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§ 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
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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
§ 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.
§ 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 § 556.92 to
BOEM.
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§ 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 § 556.76.
Notwithstanding § 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.
§ 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.
§ 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.
§ 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
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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:
Tract No.*
(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.
Total amount bid
64699
(d) The transferee of a credit
transferred under this section may use
it in accordance with § 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 per acre (or per hectare)
Amount of cash submitted
with bid
* Or, if tract numbers are not used, Protraction Diagram or Leasing Map and block number.
Proportionate interest of company(s)
submitting bid
Bidder qualification No.
Name and address of bidding company
ll Misc. No.
llllllllllllllllllll,
Authorized signatory’s name and title.
PART 559—MINERAL LEASING:
DEFINITIONS
Sec.
559.001
559.002
Purpose and scope.
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.
§ 559.001
Purpose and scope.
The purpose of this part 559 is to
define various terms appearing in part
560.
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§ 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
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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?
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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?
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Subpart C—[Reserved]
Subpart B—Bidding Systems
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?
General Provisions
§ 560.101
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.
Authority: 43 U.S.C. 1331 et seq.
Subpart A—General Provisions
§ 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.
§ 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.
§ 560.3 What is BOEM’s authority to
collect information?
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What is the purpose of this
(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.
§ 560.102
subpart?
What definitions apply to this
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.
§ 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 the . . .
And the characteristics are . . .
(a) Cash bonus bid with a fixed royalty rate of not less than 12.5
percent,
Cash bonus,
The highest responsible qualified bidder will pay a royalty rate of 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.
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64701
For the bidding system . . .
The bid variable is the . . .
And the characteristics are . . .
(b) Royalty rate bid with fixed cash
bonus,
Royalty rate,
(c) Cash bonus bid with a sliding
royalty rate of not less than 12.5
percent at the beginning of the
lease period,
Cash bonus,
(d) Cash bonus bid with fixed share
of the net profits of no less than
30 percent,
Cash bonus,
(e) Cash bonus with variable royalty rate(s) during one or more
periods of production,
Cash bonus,
(f) Cash bonus with royalty rate(s)
based on formula(s) or schedule(s) during one or more periods
of production,
(g) Cash bonus with a fixed royalty
rate of not less than 12.5 percent, at the beginning of the
lease period, suspension of royalties for a period, volume, or
value of production, or depending
upon selected characteristics of
extraction, and with suspensions
that may vary based on the price
of production,
Cash bonus,
We will specify the fixed amount of cash bonus the highest responsible qualified bidder must pay in the Notice of OCS Lease Sale
published in the FEDERAL REGISTER.
(1) We will calculate the royalty rate the highest responsible qualified
bidder must pay using either:
(i) A sliding-scale 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.
(1) If we award you a lease as the highest responsible qualified 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.
(1) We may suspend or defer royalty for a period, volume, or value of
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.
We will base the royalty rate on formula(s) or schedule(s) specified in
the Notice of OCS Lease Sale published in the FEDERAL REGISTER.
Cash bonus,
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§ 560.111 What conditions apply to the
bidding systems that BOEM uses?
(a) For each of the bidding systems in
§ 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
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Except for periods of royalty suspension, you will pay a fixed royalty
rate of not less than 12.5 percent. If we award to you a lease
under this system, you must calculate the royalty due during the
designated period using the rate, formula, or schedule specified in
the lease. We will specify the royalty rate, formula, or schedule in
the Notice of OCS Lease Sale published in the Federal Register.
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
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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 § 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
§ 560.112 How do royalty suspension
volumes apply to eligible leases?
Royalty suspension volumes, as
specified in section 304 of the Act,
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apply to eligible leases that meet the
criteria in § 560.113. For purposes of
this section and §§ 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.
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
§ 560.120 How does royalty suspension
apply to leases issued in a sale held after
November 2000?
(a) Your eligible lease will receive a
royalty suspension volume as specified
in the Act. The bidding system in
§ 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.
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 §§ 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.
§ 560.114 How does BOEM assign and
monitor royalty suspension volumes for
eligible leases?
§ 560.121 When does a lease issued in a
sale held after November 2000 get a royalty
suspension?
(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):
(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.
§ 560.113 When does an eligible lease
qualify for a royalty suspension volume?
Water depth
(1) 200 to less than
400 meters.
(2) 400 to less than
800 meters.
(3) 800 meters or more
Minimum royalty
suspension volume
17.5 MMBOE.
52.5 MMBOE.
87.5 MMBOE.
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§ 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.
§ 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
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§ 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
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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 §§ 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.
§ 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.
§ 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
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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
§ 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 (§§ 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
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§ 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 § 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;
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(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]
64703
(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
570.2
570.3
570.4
570.5
570.6
570.7
Purpose.
Application of this part.
Definitions.
Discrimination prohibited.
Complaint.
Process.
Remedies.
Authority: 43 U.S.C. 1863.
Subpart D—Joint Bidding
§ 570.1
§ 560.301
subpart?
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.’’
What is the purpose of this
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.
§ 560.302
subpart?
What definitions apply to this
For the purposes of this subpart, all
terms used are defined as in 30 CFR
556.40.
§ 560.303 What are the joint bidding
requirements?
(a) You must file a Statement of
Production with the Director, according
to the requirements of §§ 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 6month bidding period with any other
person similarly chargeable. We will
disqualify and reject these bids.
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§ 570.2
Purpose.
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.
§ 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,
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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.
§ 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.
§ 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.
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§ 570.6
Process.
Whenever a Regional Director
determines on the basis of any
information, including that which may
be obtained under § 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
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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.
§ 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.
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?
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?
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?
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?
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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
§ 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.
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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
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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, 3dimensional 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
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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, geopressuredgeothermal 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
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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.
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§ 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
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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.
§ 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.
§ 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
§ 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.
§ 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;
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(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.
§ 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
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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.)
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§ 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.
Regional Supervisor for Resource Evaluation, Bureau of Ocean Energy Management, Gulf of
Mexico OCS Region, 1201 Elmwood Park Boulevard, New Orleans, LA 70123.
Regional Supervisor for Resource Evaluation, Bureau of Ocean Energy Management, Pacific
OCS Region, 770 Paseo Camarillo, Camarillo, CA 93010.
(b) Atlantic Coast, Gulf of Mexico, Puerto Rico,
or U.S. territories in the Caribbean Sea.
(c) States of California, Oregon, Washington,
Hawaii, or U.S. territories in the Pacific
Ocean.
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?
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-ofway, 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.
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§ 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.
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(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.
§ 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.
§ 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.
§ 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.
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(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
§ 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.
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(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.
§ 580.26
When may I resume activities?
The Regional Director will advise you
when you may start your permit
activities again.
§ 580.27
permit?
When may BOEM cancel my
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.
§ 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
§ 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.
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§ 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;
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(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.
§ 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
§ 580.32
to?
What penalties may I be subject
(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
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penalty imposed by any other law or
regulation.
§ 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.
§ 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
§ 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.
§ 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;
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(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.
§ 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 § 580.40(a)
and is subject to the penalty provisions
of § 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
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§ 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 inhouse 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
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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.
(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.
§ 580.51 What types of geophysical data
and information must I submit to BOEM?
Reimbursement
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.
§ 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 § 580.50(a)
and is subject to the penalty provisions
of § 580.32(a)(1) and 30 CFR 550,
subpart N; and
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§ 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 §§ 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.
§ 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.
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Protections
§ 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.
§ 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:
If you or a third party submits and we retain . . .
The Regional Director will disclose them to the public . . .
(1)
(2)
(3)
(4)
10 years after issuing the permit.
50 years after you or a third party submit the data.
25 years after you or a third party submit the information.
25 years after you complete the test, unless the provisions of paragraph (b) of this section apply.
Geological data and information,
Geophysical data,
Geophysical information,
Data and information related to a deep stratigraphic test,
(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.
mstockstill on DSK4VPTVN1PROD with RULES2
§ 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
§ 580.40 or § 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.
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§ 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
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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
§ 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.
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(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 § 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
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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.
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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
§ 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.
§ 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.
§ 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)).
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§ 581.3
64711
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
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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.
§ 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.
§ 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.
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§ 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 § 581.21 of this part.
§ 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
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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).
§ 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.
§ 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.
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Subpart B—Leasing Procedures
§ 581.11
sale.
Unsolicited request for a lease
(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.
§ 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 § 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
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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.
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§ 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:
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(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).
§ 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 § 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.
§ 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.
§ 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 § 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
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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.
§ 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.
§ 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,
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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 § 581.33.
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§ 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.
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§ 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.
§ 581.21
Award of leases.
(a)(1) The decision of the Director on
bids shall be the final action of the
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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
§ 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 § 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.
§ 581.22
Lease form.
The OCS mineral leases shall be
issued on the lease form prescribed by
the Secretary in the leasing notice.
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§ 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
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§ 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
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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 c
the amount specified in the lease
pursuant to § 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.
§ 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 § 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.
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64715
(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.
§ 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.
§ 581.29
Royalty valuation.
Unless stated otherwise in the leasing
notice and subsequently issued lease,
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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.
§ 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
§ 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.
§ 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 § 581.30 of this
part, paragraph (a) of this section, and
§ 581.32 of this part.
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§ 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,
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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.
§ 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.
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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 § 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
§ 581.40
therein.
Assignment of leases or interests
(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.
§ 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
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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 § 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 § 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.
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§ 581.42
lease.
Effect of assignment on particular
(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
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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.
§ 581.43
term.
Effect of suspensions on lease
(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
§ 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.
§ 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
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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
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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
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.
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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.
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§ 582.2
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]
§ 582.3
Subpart D—Payments
582.40
582.41
582.42
Bonds.
Method of royalty calculation.
Payments.
Subpart E—Appeals
582.50
Appeals.
Authority: 43 U.S.C. 1334.
Subpart A—General
§ 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.
§ 582.1
Subpart A—General
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Subpart C—Obligations and
Responsibilities of Lessees
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.
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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.
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
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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
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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.
§ 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
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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
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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).
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§ 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.
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§ 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.
§ 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
§ 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
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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.
§ 582.11
Director’s authority.
(a) In the exercise of jurisdiction
under § 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
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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.
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§ 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;
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(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 § 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 § 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
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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 § 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;
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(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 § 581.26(i) of this
chapter.
(h) [Reserved]
§ 582.13
[Reserved]
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§ 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
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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)).
§ 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
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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
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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
mstockstill on DSK4VPTVN1PROD with RULES2
§ 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
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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
§ 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
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64723
needed to carry out exploration, testing,
development, and production activities
under a lease issued under 30 CFR part
581 of this title.
§ 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
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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.
mstockstill on DSK4VPTVN1PROD with RULES2
§ 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.
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(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
§ 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.
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(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.
§ 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
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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 § 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.
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§ 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
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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.
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64725
(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 § 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.
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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 §§ 582.21, 582.22, 582.23,
and 582.24 of this part.
§ 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 § 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.
§ 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]
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§ 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
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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, §§ 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 commercialscale 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
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shall be designed for the site and mining
activities described in the approved
Delineation, Testing, or Mining Plan.
§ 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;
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(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 § 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
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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.
§ 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.
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§ 582.31
64727
[Reserved]
Subpart D—Payments
§ 582.40
Bonds.
(a) Pursuant to the requirements for a
bond in § 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
§ 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
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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.
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?
§ 582.41
Subpart B—Issuance of OCS Renewable
Energy Leases
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.
§ 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 § 581.26.
Subpart E—Appeals
§ 582.50
Appeals.
See 30 CFR part 590 for instructions
on how to appeal any order or decision
that we issue under this part.
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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?
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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?
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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?
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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]
585.432 When does my lease or grant
terminate?
585.433 What must I do after my lease or
grant terminates?
585.434 [Reserved]
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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?
585.437 When can my lease or grant be
canceled?
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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
Lease or Grant Termination
Lease or Grant Cancellation
Subpart E—Payments and Financial
Assurance Requirements
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?
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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]
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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
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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?
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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?
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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 selfinspections?
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?
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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?
§ 585.101
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]
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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
§ 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
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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.
What is the purpose of this part?
The purpose of this part is to:
(a) Establish procedures for issuance
and administration of leases, right-ofway (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.
§ 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
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64731
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.
§ 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
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(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.
§ 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.
§ 585.105 What are my responsibilities
under this part?
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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.
§ 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
(1) Original certificate or certified copy 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/Assistant Secretary over corporate
seal, certifying that the corporation is authorized to hold OCS
leases.
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§ 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:
Corp.
Requirements to qualify to hold leases or grants on the OCS:
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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.
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Corp.
Requirements to qualify to hold leases or grants on the OCS:
(3) Evidence of authority of titled 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 of partnership or organization
paperwork registering with the appropriate State official.
(5) Copy of articles of partnership or 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 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 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, 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 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 by Secretary/Assistant Secretary or any member or manager of LLC.
(11) Copy of trust agreement or document 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 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.
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§ 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.
§ 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
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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.
§ 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.
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§ 585.111 When and how does BOEM
charge me processing fees on a case-bycase 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:
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(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.
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§ 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-ofuse 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
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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
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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-ofuse and easement, or alternate use rightof-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
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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
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64735
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.
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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.
§ 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.
If you have a . . .
Then BOEM will review data and 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.
At 3 years after the lease terminates.
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.
(2) Limited lease .......................................................................................
(3) ROW or RUE grant .............................................................................
(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.
§ 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 Form (OMB Control No.)
Reasons for collecting 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.
To provide BOEM with 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.
To issue ROW grants and RUE grants for OCS renewable energy activities that are not associated with a BOEM-issued renewable energy lease.
To ensure compliance with regulations pertaining to a lease or grant;
assignment and designation of operator; and suspension, renewal,
termination, relinquishment, and cancellation of leases and grants.
To ensure that payments and financial assurance payments for renewable energy leases comply with subpart E.
To enable BOEM to comply with 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.
To enable BOEM to review the 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.
(2) Subpart B—Issuance of OCS Renewable Energy Leases ................
(3) Subpart C—ROW Grants and RUE Grants for Renewable Energy
Activities.
(4) Subpart D—Lease and Grant Administration .....................................
(5) Subpart E—Payments and Financial Assurance Requirements ........
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(6) Subpart F—Plans and Information Requirements ..............................
(7) Subpart G—Facility Design, Fabrication, and Installation ..................
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30 CFR 585 subpart, title, and/or BOEM Form (OMB Control No.)
Reasons for collecting information and how used
(8) Subpart H—Environmental and Safety Management, Inspections,
and Facility Assessments.
To ensure that lease and grant operations are conducted in a manner
that is safe and protects the environment. To ensure compliance with
other Federal laws, these regulations, the lease or grant, and approved plans.
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.
To enable BOEM to review information regarding the 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.
(9) Subpart I—Decommissioning .............................................................
(10) Subpart J—RUEs for Energy and Marine-Related Activities Using
Existing OCS Facilities.
§ 585.115 Documents incorporated by
reference.
(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
(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
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: https://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. https://www.api.org/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, 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.
mstockstill on DSK4VPTVN1PROD with RULES2
§ 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
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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
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30 CFR 585.825
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.
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§ 585.117
§ 585.118
Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations
[Reserved]
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
mstockstill on DSK4VPTVN1PROD with RULES2
§ 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,
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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
§ 585.629.
§ 585.201
How will BOEM issue leases?
BOEM will issue leases on a
competitive basis, as provided under
§§ 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 §§ 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 §§ 585.211 and 585.231.
§ 585.202
issue?
What types of leases will BOEM
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.
§ 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).
§ 585.204 What areas are available for
leasing consideration?
BOEM may offer any appropriately
platted area of the OCS, as provided in
§ 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.
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§ 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.
§ 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.
§§ 585.207–585.209
[Reserved]
Competitive Lease Process
§ 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.
§ 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
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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.
noncompetitive process, the acquisition
fee specified in § 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
§§ 585.211 through 585.225.
§ 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 § 585.113.
(e) Documentation showing that you
are qualified to hold a lease, as specified
in § 585.107.
(f) Any other information requested
by BOEM in the Federal Register notice.
mstockstill on DSK4VPTVN1PROD with RULES2
§ 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?
§ 585.214 What will BOEM do with
information from the Requests for
Information or Calls for Information and
Nominations?
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
§ 585.231(d) through (i). Under the
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.
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§ 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 § 585.211 of this part. We will not
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64739
accept nominations after the Call for
Information and Nominations closes.
§ 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 decisionmaking 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.
§§ 585.217–585.219
[Reserved]
Competitive Lease Award Process
§ 585.220 What auction format may BOEM
use in a lease sale?
(a) Except as provided in § 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:
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Type of auction
Bid variable
Bidding process
(1) Sealed bidding ..............................................
A cash bonus or an operating fee rate ............
(2) Ascending bidding ........................................
(3) Two-stage bidding (combination of ascending and sealed bidding).
A cash bonus or an operating fee rate ............
An operating fee rate in one, both, or neither
stage and a cash bonus in one, both, or
neither stage.
(4) Multiple-factor bidding ...................................
Factors may include, but are not limited to:
technical merit, timeliness, financing and
economics, environmental considerations,
public benefits, compatibility with State and
local needs, cash bonus, rental rate, and an
operating fee rate.
One sealed bid per company per lease or
packaged bidding unit.
Continuous bidding per lease.
Ascending or sealed bidding until:
(i) Only two bidders remain, or
(ii) More than one 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.
One proposal per company per lease or packaged bidding unit.
(b) You must submit your bid and a
deposit as specified in §§ 585.500 and
585.501 to cover the bid for each lease
area, according to the terms specified in
the Final Sale Notice.
§ 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 (decimal) ..................................
(2) Constant operating fee rate with fixed cash bonus ............................
Cash bonus.
A fee rate used in the formula found in § 585.506 to set the operating
fee per year during the operations term of your lease.
A fee rate used in the formula in § 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.
Cash bonus and operating fee rate as stated in paragraph (2) of this
section (two-stage auction format only).
Cash bonus and operating fee rate as stated in paragraph (3) of this
section (two-stage auction format only).
BOEM will identify bidding 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.
(3) Sliding operating fee rate with a fixed cash bonus ............................
(4) Cash bonus and constant operating fee rate .....................................
(5) Cash bonus and sliding operating fee rate ........................................
(6) Multiple-factor combination of nonmonetary and monetary 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.
mstockstill on DSK4VPTVN1PROD with RULES2
§ 585.222
bid?
What does BOEM do with my
(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, anticompetitive behavior, administrative
error, and the presence of unusual
bidding patterns. We intend to accept or
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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
§ 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.
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(e) We will send a written notice of
our decision to accept or reject bids to
all bidders whose deposits we hold.
§ 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.
§ 585.224
my bid?
What happens if BOEM accepts
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;
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(2) File financial assurance as
required under §§ 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 § 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 § 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 § 585.222(d) when
the bidding system under
§ 585.221(a)(6) is used. We will refund
the deposit on all other bids.
mstockstill on DSK4VPTVN1PROD with RULES2
§ 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
§ 585.118(c)(1). We will send you a
written response either affirming or
reversing the rejection.
§§ 585.226–585.229
[Reserved]
Noncompetitive Lease Award Process
§ 585.230
no Call?
May I request a lease if there is
You may submit an unsolicited
request for a commercial lease or a
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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 § 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 § 585.107.
(g) An acquisition fee, as specified in
§ 585.502(a).
§ 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
§§ 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
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64741
(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 §§ 585.605 through
585.613; or
(ii) For a limited lease, a GAP, as
described in §§ 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 §§ 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 § 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.
§ 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
§ 585.502(a).
(c) After receiving the acquisition fee,
BOEM will follow the process outlined
in § 585.231(b) through (i).
§ 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?
(a) For commercial leases, the lease
terms and applicable automatic
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extensions are as shown in the
following table:
Lease term
Automatic extensions
Requirements
(1) Each commercial lease issued competitively
will have a preliminary term of 6 months to
submit:
(i) a SAP; or
(ii) a combined SAP and COP. The preliminary term begins on the effective date of
the lease. A commercial lease issued
noncompetitively does not have a preliminary term.
(2) A commercial lease will have a site assessment term of 5 years to conduct site assessment activities and to submit a COP, if a
SAP/COP has not been submitted. Your site
assessment term begins when BOEM approves your SAP or SAP/COP.
(3) A commercial lease will have an operations
term of 25 years, unless a longer term is negotiated by applicable parties.
A request for lease renewal 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 have additional
time added to the operations term through a
lease renewal. The term of the lease renewal
will not exceed the original term of the lease,
unless a longer term is negotiated by applicable parties. The lease renewal term begins
upon expiration of the original operations
term.
If we receive a SAP that satisfies the requirements of §§ 585.605 through 585.613 or a
SAP/COP that satisfies the requirements of
§§ 585.605 through 585.613 and §§ 585.620
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.
The SAP must meet the requirements of
§§ 585.605 through 585.613. The SAP/COP
must meet the requirements of §§ 585.605
through 585.613 and §§ 585.620 through
585.629.
If we receive a COP that satisfies the requirements of §§ 585.620 through 585.629, the
site assessment term will be automatically
extended for the period of time necessary
for us to conduct technical and environmental reviews of the COP.
......................................................................
The COP must meet the requirements of
§§ 585.620 through 585.629 of this part.
(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.
The lease renewal request must meet the requirements, as provided in §§ 585.425
through 585.429.
We may order or grant a suspension of the
operations term, as provided in §§ 585.415
through 585.421.
§ 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:
Lease term
Extension or suspension
Requirements
(1) Each limited lease issued competitively has
a preliminary term of 6 months to submit a
GAP. The preliminary term begins on the effective date of the lease.
If we receive a GAP that satisfies the requirements of §§ 585.640 through 585.648 of
this part, the preliminary term will be automatically extended for the period of time
necessary for us to conduct a technical and
environmental review of the plans.
......................................................................
The GAP must meet the requirements of
§§ 585.640 through 585.648.
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(2) The operations term begins when BOEM
approves your GAP and issues your lease. A
limited lease issued noncompetitively does
not have a preliminary term.
(3) Each limited lease has an operations term
of 5 years for conducting site assessment,
technology testing, or other activities. The operations term begins on the date 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.
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You must submit and BOEM must approve
your GAP before we will issue a lease. The
GAP must meet the requirements of
§§ 585.640 through 585.648.
We may order or grant a suspension of the
operations term as provided in §§ 585.415
through 585.421.
§ 585.237
lease?
What is the effective date of a
(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.
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(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.
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§ 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
(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.
ROW Grants and RUE Grants
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§ 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 § 585.200(b) to serve
your lease.
§ 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.
§ 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 § 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
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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.
§ 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.
§ 585.304
[Reserved]
Obtaining ROW Grants and RUE
Grants
§ 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.
§ 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 § 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
§ 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 §§ 585.640 through
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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 §§ 585.640
through 585.648.
§ 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.
§ 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
§§ 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 § 585.316.
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§ 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.
§ 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.
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§§ 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?
(a) You must make a deposit, as
required in § 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.
§ 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 § 585.508.
Subpart D—Lease and Grant
Administration
§ 585.401, and/or a cancellation of the
lease or grant as provided in § 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.
Noncompliance and Cessation Orders
§ 585.401 When may BOEM issue a
cessation order?
§ 585.400 What happens if I fail to comply
with this part?
(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 § 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.
(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
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§ 585.402
order?
What is the effect of a cessation
(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 § 585.437.
(c) A cessation order does not extend
the term of your lease or grant for the
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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.
§ 585.403
[Reserved]
§ 585.404
[Reserved]
Designation of Operator
§ 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
§ 585.610(a)(3)), COP (under
§ 585.626(b)(2)), or GAP (under
§ 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.
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§ 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
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lease or grant and this part, BOEM may
require you or any or all of your colessees 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.
§ 585.407
[Reserved]
Lease or Grant Assignment
§ 585.408
interest?
May I assign my lease or grant
(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 § 585.107;
and
(8) A statement on how the assignee
will comply with the financial
assurance requirements of §§ 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,
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or changes of business form. You must
notify BOEM of these events under
§ 585.109.
§ 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
§§ 585.515 through 585.537.
(c) The assignee must submit proof of
eligibility and other qualifications
specified in § 585.107.
(d) Persons executing on behalf of the
assignor and assignee must furnish
evidence of authority to execute the
assignment.
§ 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.
§ 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.
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§§ 585.412–585.414
[Reserved]
Lease or Grant Suspension
§ 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 § 585.416; or
(2) As ordered by BOEM, as provided
in § 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.
§ 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.
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§ 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
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may require you to conduct a sitespecific 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.
that is suspended, depending on the
reasons for the requested suspension.
(c) If BOEM orders a suspension, as
provided in § 585.417, your payments,
as appropriate for the term that is
suspended, will be waived during the
suspension period.
§ 585.421
effect?
How long will a suspension be in
A suspension will be in effect for the
period specified by BOEM.
(a) BOEM will not approve a
suspension request pursuant to
§ 585.416 for a period longer than 2
years.
(b) If BOEM determines that the
circumstances giving rise to a
suspension ordered under § 585.417
cannot be resolved within 5 years, the
Secretary may initiate cancellation of
the lease or grant, as provided in
§ 585.437.
§§ 585.422–585.424
[Reserved]
Lease or Grant Renewal
§ 585.418 How will BOEM issue a
suspension?
§ 585.425 May I obtain a renewal of my
lease or grant before it terminates?
(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.
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.
§ 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.
§ 585.420 What effect does a suspension
order have on my payments?
(a) While BOEM evaluates your
request for a suspension under
§ 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 § 585.416,
we may suspend your payment
obligation, as appropriate for the term
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§ 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.
§ 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.
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(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.
§ 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
§ 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.
§ 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.
§ 585.430
[Reserved]
§ 585.431
[Reserved]
Lease or Grant Termination
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§ 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
§§ 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
§ 585.437; or
(c) Relinquishment, as set forth in
§ 585.435.
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§ 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.
§ 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?
(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.
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64747
(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
§ 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 § 585.118 of this part.
Lease or Grant Cancellation
§ 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 § 585.635, or other approved
activities under your GAP, as provided
in § 585.656;
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(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
§ 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
Payment
Amount
Due date
instrument. You may access the Pay.gov
Web site through links on the BOEM
Offshore Web site at: https://
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 mechanism
Section reference
Initial payments for leases
(1) If your lease is issued
competitively,
(2) If your lease is issued
non-competitively.
(3) All leases .....................
Bid Deposit ..............
Bonus Balance ........
Acquisition Fee ........
Initial Rent ...............
As set in Final Sale
Notice/depends on
bid.
..................................
$0.25 per acre, unless otherwise set
by the Director.
$3 per acre per year
With bid ...................
Pay.Gov ...................
§ 585.501.
Lease issuance .......
With application .......
30 CFR 1218.51.
Pay.gov ....................
§ 585.502.
45 days after lease
issuance.
Pay.gov ....................
§ 585.503.
Subsequent payments for leases and project easements
(4) All leases .....................
Subsequent Rent .....
$3 per acre per year
Annually ...................
30 CFR 1218.51 ......
(5) If you have a project
easement.
Rent .........................
Greater of $5 per
acre per year or
$450 per year.
30 CFR 1218.51 ......
(7) If your commercial
lease is producing,
Operating Fee ..........
Determined by the
formula in
§ 585.506.
When operations
term for associated lease starts,
then annually.
Annually ...................
§§ 585.503 and
585.504.
§ 585.507.
30 CFR 1218.51 ......
§ 585.506.
Grant Issuance ........
Pay.gov ....................
§ 585.508.
Annually or in 5-year
batches.
30 CFR 1218.51.
Payments for ROW grants and RUE grants*
(8) All ROW grants and
RUE grants.
Initial Rent ...............
Subsequent Rent .....
$70 per statute mile,
and the greater of
$5 per acre per
year or $450 per
year.
..................................
* There is no acquisition fee for ROW grants or RUE grants.
mstockstill on DSK4VPTVN1PROD with RULES2
§ 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
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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.
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§ 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
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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 § 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 § 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.
set by the Director, as provided in
§ 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.
§ 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 § 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 § 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
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F
(annual operating
fee)
=
M
(nameplate
capacity)
16:55 Oct 17, 2011
Jkt 226001
If you develop your commercial lease
in phases, as approved by us in your
COP under § 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 § 585.506 and as described
in § 585.503(b).
(c) Rent for a project easement in
addition to lease rent, as provided in
§ 585.507. You must commence rent
payments for your project easement
upon our approval of your COP.
§ 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.
H
(hours per year)
*
(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
VerDate Mar<15>2010
§ 585.504 How are my payments affected if
I develop my lease in phases?
*
c
(capacity factor)
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 § 585.510.
(2) The power price ‘‘P,’’ for each year
when the operating fee applies, will be
determined annually. The process by
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64749
(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 § 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.
§ 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
§ 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:
*
P
(power price)
*
r
(operating fee
rate)
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
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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 § 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.
§ 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
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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 § 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.
§ 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 § 585.500, and all
subsequent rent payments to ONRR in
accordance with the regulations at 30
CFR 1218.51.
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§ 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.
§ 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.
§ 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?
(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, leasespecific bond; or
(2) Another approved financial
assurance instrument guaranteeing
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performance up to $100,000, as
specified in §§ 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 IndexAll 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.
§ 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 an assignment of an existing
commercial lease.
(2) Approve your SAP ..............................................................................
A $100,000 minimum, lease-specific financial assurance.
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 leasespecific bond, due to the complexity, number, and location of any facilities involved in your site assessment activities.
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.
A decommissioning bond or other 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.
(3) Approve your COP ..............................................................................
(4) Allow you to install facilities approved in your COP ...........................
(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.
§ 585.517 How will BOEM determine the
amounts of the supplemental and
decommissioning financial assurance
requirements associated with commercial
leases?
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64751
(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
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(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.
§§ 585.518–585.519
[Reserved]
Financial Assurance for Limited
Leases, ROW Grants, and RUE Grants
§ 585.520 What financial assurance must I
provide when I obtain my limited lease,
ROW grant, or RUE grant?
(a) Before BOEM will issue your
limited lease, ROW grant, or RUE grant,
you or a proposed assignee must
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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 §§ 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 leasespecific 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.
§ 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
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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 §§ 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.
§§ 585.522–585.524
[Reserved]
Requirements for Financial Assurance
Instruments
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§ 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 BOEMapproved 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 https://www.fms.treas.gov/c570/.
(d) Your surety bond cannot exceed
the underwriting limit listed in the
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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.
§ 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
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(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 https://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.
§ 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
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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.
§ 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.
64753
(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 recently completed FY ..................
Include a report by an 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.
Your guarantor’s financial officer certifies to be correct.
Your guarantor’s financial officer certifies to be correct.
mstockstill on DSK4VPTVN1PROD with RULES2
(ii) Financial statement for completed quarter in the current FY .............
(iii) Additional information related to bonds, if requested by the Director
(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 § 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
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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
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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.
§ 585.529 Can I use a lease- or grantspecific 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 grantspecific 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
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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 https://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
§ 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.
§ 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.
§ 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.
§ 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 §§ 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.
§ 585.534
bond?
When may BOEM cancel my
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:
The period of liability ends . . .
Your bond will not be released until . . .
(a) Bonds for commercial leases submitted
under § 585.515.
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Bond
When BOEM determines that you have met
all of your obligations under the lease.
(b) Supplemental or decommissioning bonds
submitted under § 585.516.
When BOEM determines that you have met
all your decommissioning, site clearance,
and other obligations.
Seven years after the lease ends, or a longer
period as necessary to 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.
(1) Seven years after the lease ends, or a
longer period as necessary to 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; and
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Bond
The period of liability ends . . .
(c) Bonds submitted under §§ 585.520 and
585.521 for limited leases, ROW grants, or
RUE grants.
§ 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.
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§ 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.
§ 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
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Your bond will not be released until . . .
When BOEM determines that you have met
all of your obligations under the limited
lease or grant.
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.
§§ 585.538–585.539
[Reserved]
Revenue Sharing With States
§ 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 § 585.541 and an eligible
State is determined in § 585.542, with
each term defined in § 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 §§ 585.435 or
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64755
(2) BOEM determines that the potential liability resulting from any undetected noncompliance is not greater than the amount
of the lease base bond.
Seven years after the limited lease, ROW, or
RUE grant or a longer period as necessary
to 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.
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) ÷ (Si=1* * *n(1/Si)).
§ 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 § 585.542. The
entire area within a lease or grant for the
qualified project, excluding project
easements, is considered the qualified
project area.
§ 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
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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.
§ 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 × 1⁄4 =
$67,500.
(2) State B’s share = $270,000 × 3⁄4 =
$202,500.
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?
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 on your commercial lease,
submit and obtain approval for your SAP according to §§ 585.605
through 585.613.
submit and obtain approval for your COP, according to §§ 585.620
through 585.629.
submit and obtain approval for your GAP according to §§ 585.640
through 585.648.
(b) conduct any activities pertaining to construction of facilities for commercial operations on your commercial lease,
(c) conduct any activities on your limited lease, ROW grant, or RUE
grant in any OCS area,
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§ 585.601 When am I required to submit
my plans to BOEM?
§ 585.602
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.
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What records must I maintain?
Site Assessment Plan and Information
Requirements for Commercial Leases
of the approved activities on your lease,
as provided in § 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
§ 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
§ 585.810.
§ 585.605
(SAP)?
§ 585.606
SAP?
Until BOEM releases your financial
assurance under § 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.
§§ 585.603–585.604
[Reserved]
What is a Site Assessment Plan
(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 § 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
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What must I demonstrate in my
(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
§ 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.
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(b) You must also demonstrate that
your site assessment activities will
collect the necessary information and
data required for your COP, as provided
in § 585.626(a).
§ 585.607
BOEM at the address listed in
§ 585.110(a).
§ 585.608
(a) For all activities you propose to
conduct under your SAP, you must
provide the following information:
[Reserved]
§ 585.609
64757
[Reserved]
Contents of the Site Assessment Plan
How do I submit my SAP?
You must submit one paper copy and
one electronic version of your SAP to
§ 585.610
What must I include in my SAP?
Your SAP must include the following
information, as applicable.
Project information
Including
(1) Contact information .............................................................................
The name, address, e-mail address, and phone number of an authorized representative.
A discussion of the objectives; description of the proposed activities, including the technology you will use; and proposed schedule from
start to completion.
As provided in § 585.405.
A description of the measures you took, or will take, to satisfy the conditions of any lease stipulations related to your proposed activities.
The surface location and water depth for all proposed and existing
structures, facilities, and appurtenances located both offshore and
onshore.
Information for each type of facility associated with your project.
A description of the safety, prevention, and environmental protection
features or measures that you will use.
A description of the measures you will use to avoid or minimize adverse effects and 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.
CVA nominations for reports in subpart G of this part, as required by
§ 585.706, or a request to waive the CVA requirement, as required
by § 585.705(c).
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.
A discussion of methodologies.
Information as described in § 585.659 of this section.
A statement indicating whether such authorization or approval has
been applied for or obtained.
Contact information and issues discussed.
(2) The site assessment or technology testing concept ..........................
(3) Designation of operator, if applicable .................................................
(4) Commercial lease stipulations and compliance .................................
(5) A location plat .....................................................................................
(6) General structural and project design, fabrication, and installation ...
(7) Deployment activities ..........................................................................
(8) Your proposed measures for avoiding, minimizing, reducing, eliminating, and monitoring environmental impacts.
(9) CVA nomination, if required ................................................................
(10) Reference information .......................................................................
(11) Decommissioning and site clearance procedures ............................
(12) Air quality information .......................................................................
(13) A listing of all Federal, State, and local authorizations or approvals
required to conduct site assessment activities on your lease.
(14) A list of agencies and persons with whom you have communicated, or with whom you will communicate, regarding potential impacts associated with your proposed activities.
(15) Financial assurance information .......................................................
(16) Other information ..............................................................................
(b) You must provide the results of
geophysical and geological surveys,
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 §§ 585.515 and 585.516.
Additional information as requested by BOEM.
hazards surveys, archaeological surveys
(if required), and baseline collection
studies (e.g., biological) with the
supporting data in your SAP:
Report contents
Including
(1) Geotechnical ...................
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Information
The results from the geotechnical survey with supporting data.
A description of all relevant seabed and engineering
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.
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Information
Report contents
Including
(2) Shallow hazards .............
The results from the shallow hazards survey with supporting data.
(3) Archaeological resources
The results from the archaeological survey with supporting data, if required.
(4) Geological survey ...........
The results from the geological survey with supporting
data.
(5) Biological survey ............
The results from the biological survey with supporting
data.
A description of information sufficient to 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.
(i) A description of the results and data from the
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.
A report that describes the results of a 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.
A description of the results of a biological survey, 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.
§ 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.
Turbidity and total suspended solids from construction.
Benthic communities, marine mammals, sea turtles, coastal and marine
birds, fish and shellfish, plankton, seagrasses, and plant life.
As required by the Endangered Species Act (ESA) of 1973 (16 U.S.C.
1531 et seq.).
Essential fish habitat, 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.
As required by the NHPA (16 U.S.C. 470 et seq.), as amended.
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.
Military activities, vessel traffic, and energy and nonenergy mineral exploration or development.
(2) Water quality .......................................................................................
(3) Biological resources ............................................................................
(4) Threatened or endangered species ....................................................
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(5) Sensitive biological resources or habitats ..........................................
(6) Archaeological resources ....................................................................
(7) Social and economic resources ..........................................................
(8) Coastal and marine uses ....................................................................
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Type of information
64759
Including
(9) Consistency Certification ....................................................................
(10) Other resources, conditions, and activities .......................................
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.
As identified by BOEM.
§ 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.
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.
(b) Noncompetitively ...........................................
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§ 585.613
SAP?
How will BOEM process my
(a) BOEM will review your submitted
SAP, and additional information
provided pursuant to § 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
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certify compliance with those terms and
conditions required under § 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
§ 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 § 585.613(a)(1), you must
comply with the requirements of
subpart G of this part and submit your
Safety Management System required by
§ 585.810 before construction may
begin.
§ 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
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under exemption 4 of the FOIA and as
provided in § 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
§ 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.
§ 585.616
[Reserved]
§ 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
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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.
§ 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.
§ 585.619
[Reserved]
Construction and Operations Plan for
Commercial Leases
§ 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 § 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.
§ 585.621
COP?
What must I demonstrate in my
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 § 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.
§ 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
§ 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.
§§ 585.623 through 585.625
[Reserved]
Contents of the Construction and
Operations Plan
§ 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 shallow hazards survey with supporting data.
Information sufficient to 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;
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Information:
Report contents:
64761
Including:
(2) Geological survey relevant to the design and
siting of your facility.
The results of the geological survey with supporting
data.
(3) Biological ........................
The results of the biological survey with supporting data
(4) Geotechnical survey .......
The results of your sediment testing program with supporting data, 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 sediment, and the anticipated design
application. You must explain how the engineering
properties of each sediment stratum affect the design
of your facility. In your explanation, you must describe the uncertainties inherent in your overall testing program, and the reliability and applicability of
each test method.
(5) Archaeological resources
The results of the archaeological resource survey with
supporting data.
(6) Overall site investigation
An overall site investigation report for your facility that
integrates the findings of your shallow hazards surveys and geologic surveys, and, if required, your
subsurface surveys with supporting data.
(iv) Hydrates; or
(v) Ice scour of seabed sediments.
Assessment 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.
A description of the results of biological surveys 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.
(i) The results of a testing program used to investigate
the stratigraphic and engineering properties of the
sediment that may affect the foundations or anchoring systems for your facility.
(ii) The results of adequate in situ testing, boring, and
sampling at each foundation location, to examine all
important sediment and rock strata to determine its
strength classification, deformation properties, and
dynamic characteristics.
(iii) The results of a minimum of one deep boring (with
soil sampling and 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.
A description of the historic and prehistoric archaeological resources, as required by the NHPA (16
U.S.C. 470 et. seq.), as amended.
An analysis of the potential for:
(i) Scouring of the seabed;
(ii) Hydraulic instability;
(iii) The occurrence of sand waves;
(iv) Instability of slopes at the facility location;
(v) Liquefaction, or 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.
As provided in § 585.405.
A discussion of the objectives, description of the proposed activities,
tentative schedule from start to completion, and plans for phased development, as provided in § 585.629.
A description of the measures you took, or will take, to satisfy the conditions of any lease stipulations related to your proposed activities.
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.
Information for each type of 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.
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(2) Designation of operator, if applicable .................................................
(3) The construction and operation concept ............................................
(4) Commercial lease stipulations and compliance .................................
(5) A location plat .....................................................................................
(6) General structural and project design, fabrication, and installation ...
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Project information:
Including:
(7) All cables and pipelines, including cables on project easements ......
Location, design and installation methods, testing, maintenance, repair,
safety devices, exterior corrosion protection, inspections, and decommissioning.
Safety, prevention, and environmental protection features or measures
that you will use.
Disposal methods and locations.
A list of chemical products used; the volume stored on 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
that will be transferred each time.
An estimate of the frequency and duration of vessel/vehicle/aircraft traffic.
(i) Under normal conditions.
(ii) In the case of accidents or emergencies, including those that are
natural or manmade.
A discussion of general concepts and methodologies.
(i) The U.S. Coast Guard, U.S. Army Corps Of Engineers, and any
other applicable authorizations, approvals, or 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.
A description of the measures you will use to avoid or minimize adverse effects and 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.
A listing of the documents you referenced.
Contact information and issues discussed.
(8) A description of the deployment activities ..........................................
(9) A list of solid and liquid wastes generated .........................................
(10) A listing of chemical products used (if stored volume exceeds Environmental Protection Agency (EPA) Reportable Quantities).
(11) A description of any vessels, vehicles, and aircraft you will use to
support your activities.
(12) A general description of the operating procedures and systems .....
(13) Decommissioning and site clearance procedures ............................
(14) A listing of all Federal, State, and local authorizations, approvals,
or permits that are required to conduct the proposed activities, including commercial operations.
(15) Your proposed measures for avoiding, minimizing, reducing, eliminating, and monitoring environmental impacts.
(16) Information you incorporate by reference .........................................
(17) A list of agencies and persons with whom you have communicated, or with whom you will communicate, regarding potential impacts associated with your proposed activities.
(18) Reference ..........................................................................................
(19) Financial assurance ..........................................................................
(20) CVA nominations for reports required in subpart G of this part ......
(21) Construction schedule ......................................................................
(22) Air quality information .......................................................................
(23) Other information ..............................................................................
§ 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
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.
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 §§ 585.515 and 585.516.
CVA nominations for reports in subpart G of this part, as required by
§ 585.706, or a request for a waiver under § 585.705(c).
A reasonable schedule of construction activity showing significant milestones leading to the commencement of commercial operations.
As described in § 585.659 of this section.
Additional information as required by BOEM.
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.
Turbidity and total suspended solids from construction.
Benthic communities, marine mammals, sea turtles, coastal and marine
birds, fish and shellfish, plankton, seagrasses, and plant life.
As defined by the ESA (16 U.S.C. 1531 et seq.).
Essential fish habitat, 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.
As required by the NHPA (16 U.S.C. 470 et seq.), as amended.
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(2) Water quality .......................................................................................
(3) Biological resources ............................................................................
(4) Threatened or endangered species ....................................................
(5) Sensitive biological resources or habitats ..........................................
(6) Archaeological resources ....................................................................
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Type of information:
Including:
(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.
Military activities, vessel traffic, and energy and nonenergy mineral exploration or development.
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.
As identified by BOEM.
(8) Coastal and marine uses ....................................................................
(9) Consistency Certification ....................................................................
(10) Other resources, conditions, and activities .......................................
(b) You must submit one paper copy
and one electronic copy of your
consistency certification. Your
consistency certification must include:
(1) One copy of your consistency
certification under 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
§ 585.810.
mstockstill on DSK4VPTVN1PROD with RULES2
§ 585.628
COP?
How will BOEM process my
(a) BOEM will review your submitted
COP, and the information provided
pursuant to § 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
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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
§ 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.
§ 585.629
phases?
May I develop my lease in
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.
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§ 585.630
[Reserved]
Activities Under an Approved COP
§ 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 § 585.626(b)(21), and
included as a part of your approved
COP, unless BOEM approves a deviation
from your schedule.
§ 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
found in:
Document:
(1) Facility Design Report
(2) Fabrication and Installation Report ..........
§ 585.701
§ 585.702
(b) You must submit your Safety
Management System, as required by
§ 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
§ 585.634, for BOEM approval before
commencing the activity.
§ 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
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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 § 585.105(i), BOEM
may require you to submit any
supporting data and information.
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§ 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:
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(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.
§ 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 § 585.437
and, you must initiate the
decommissioning process as set forth in
subpart I of this part.
§ 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.
§ 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
§ 585.708.
(b) Require a FERC license or
exemption, then you may commence
commercial operations when permitted
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by the terms of your license or
exemption.
§ 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 §§ 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.
§ 585.639
[Reserved]
General Activities Plan Requirements
For Limited Leases, ROW Grants, and
RUE Grants
§ 585.640
(GAP)?
What is a General Activities Plan
(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.
§ 585.641
GAP?
What must I demonstrate in my
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.
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§ 585.642
How do I submit my GAP?
§ 585.643
(a) You must submit one paper copy
and one electronic version of your GAP
to BOEM at the address listed in
§ 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.
[Reserved]
§ 585.644
[Reserved]
64765
surveys (if required), and baseline
collection studies (e.g., biological) with
the supporting data in your GAP:
Contents of the General Activities Plan
§ 585.645
What must I include in my GAP?
(a) You must provide the following
results of geophysical and geological
surveys, hazards surveys, archaeological
Information:
Report contents:
Including:
(1) Geotechnical ...................
The results from the geotechnical survey with supporting data.
(2) Shallow hazards .............
The results from the shallow hazards survey with supporting data.
(3) Archaeological resources
The results from the archaeological survey with supporting data, if required.
(4) Geological survey ...........
The results from the geological survey with supporting
data.
(5) Biological survey ............
The results from the biological survey with supporting
data.
A description of all relevant seabed and engineering
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.
A description of information sufficient to 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.
(i) A description of the results and data from the archaeological survey;
(ii) A description of the historic and prehistoric archaeological resources, as required by NHPA
(16 U.S.C. 470 et seq.), as amended.
A report that describes the results of a 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.
A description of the results of a biological survey, 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.
A discussion of the objectives; description of the proposed activities, including the technology you will use; and proposed schedule from
start to completion.
As provided in § 585.405.
A description of the measures you took, or will take, to satisfy the conditions of any lease stipulations related to your proposed activities.
The surface location and water depth for all proposed and existing
structures, facilities, and appurtenances located both offshore and
onshore.
Information for each type of facility associated with your project.
A description of the safety, prevention, and environmental protection
features or measures that you will use.
Disposal methods and locations.
(2) The site assessment or technology testing concept ..........................
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(3) Designation of operator, if applicable .................................................
(4) ROW, RUE or limited lease grant stipulations, if known ....................
(5) A location plat .....................................................................................
(6) General structural and project design, fabrication, and installation ...
(7) Deployment activities ..........................................................................
(8) A list of solid and liquid wastes generated .........................................
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Project information:
Including:
(9) A listing of chemical products used (only if stored volume exceeds
USEPA Reportable Quantities).
A list of chemical products used; the volume stored on 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.
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.
A discussion of methodologies.
As described in § 585.659 of this section.
A statement indicating whether such authorization or approval has
been applied for or obtained.
Contact information and issues discussed.
(10) Reference information .......................................................................
(11) Decommissioning and site clearance procedures ............................
(12) Air quality information .......................................................................
(13) A listing of all Federal, State, and local authorizations or approvals
required to conduct site assessment activities on your lease.
(14) A list of agencies and persons with whom you have communicated, or with whom you will communicate, regarding potential impacts associated with your proposed activities.
(15) Financial assurance information .......................................................
(16) Other information ..............................................................................
(c) If you are applying for a project
easement or constructing a facility, or a
combination of facilities deemed by
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 §§ 585.520 and 585.521.
Additional information as requested by BOEM.
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 concept ............................................
A discussion of the objectives, description of the proposed activities,
and tentative schedule from start to completion.
The location, design, installation methods, testing, maintenance, repair,
safety devices, exterior corrosion protection, inspections, and decommissioning.
Safety, prevention, and environmental protection features or measures
that you will use.
(i) Under normal conditions.
(ii) In the case of accidents or emergencies, including those that are
natural or manmade.
CVA nominations for reports in subpart G of this part, as required by
§ 585.706, or a request for a waiver under § 585.705(c).
A reasonable schedule of construction activity showing significant milestones leading to the commencement of activities.
Additional information as required by the BOEM.
(2) All cables and pipelines, including cables on project easements ......
(3) A description of the deployment activities ..........................................
(4) A general description of the operating procedures and systems .......
(5) CVA nominations for reports required in subpart G of this part ........
(6) Construction schedule ........................................................................
(7) Other information ................................................................................
(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 § 585.113.
§ 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.
Turbidity and total suspended solids from construction.
Benthic communities, marine mammals, sea turtles, coastal and marine
birds, fish and shellfish, plankton, seagrasses, and plant life.
As required by the ESA (16 U.S.C. 1531 et seq.).
Essential fish habitat, 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.
As required by NHPA (16 U.S.C. 470 et seq.), as amended.
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(b) Water quality .......................................................................................
(c) Biological resources ............................................................................
(d) Threatened or endangered species ....................................................
(e) Sensitive biological resources or habitats ..........................................
(f) Archaeological resources .....................................................................
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Type of information:
Including:
(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.
Military activities, vessel traffic, and energy and nonenergy mineral exploration or development.
As required by CZMA:
(1) 15 CFR part 930, subpart D, for noncompetitive leases;
(2) 15 CFR part 930, subpart E, for competitive leases.
As required by BOEM.
(h) Coastal and marine uses ....................................................................
(i) Consistency Certification ......................................................................
(j) Other resources, conditions, and activities ..........................................
§ 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.
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.
(b) Noncompetitively,
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§ 585.648
GAP?
How will BOEM process my
(a) BOEM will review your submitted
GAP, along with the information and
certifications provided pursuant to
§ 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
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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
§ 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.
combination of facilities on your limited
lease deemed by BOEM to be complex
or significant, as provided in
§ 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 § 585.810 before
construction may begin.
§ 585.652 How long do I have to conduct
activities under an approved GAP?
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 §§ 585.425
through 585.429.
(b) For a ROW grant or RUE grant, the
time provided in the terms of the grant.
§ 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.
§ 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 § 585.113.
§ 585.649
[Reserved]
§ 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
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(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
§ 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.
§ 585.654
[Reserved]
§ 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.
§ 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 § 585.437, as applicable, and you
must initiate the decommissioning
process, as set forth in subpart I of this
part.
§ 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 §§ 585.905
and 585.906.
Cable and Pipeline Deviations
§ 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.
§ 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.
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If your project is located . . .
you must . . .
(1) in the Gulf of Mexico west of 87.5° west longitude (western Gulf of
Mexico).
(2) anywhere else on the OCS ................................................................
include in your plan any information required for BOEM to make the
appropriate air quality determinations for your project.
follow the appropriate implementing regulations as promulgated by the
EPA under 40 CFR part 55.
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(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° 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
§ 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 (§ 585.632(a)) and, when required
by this part, your SAP (§ 585.614(b)) or
GAP (§ 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
64769
request that certain actions be
undertaken. You cannot commence
activities addressed in such report until
you resolve all objections to BOEM’s
satisfaction.
§ 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
§ 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 facility designations;
(ii) Lease, ROW grant or RUE grant number;
(iii) Area; name and block numbers; and
(iv) The type of facility.
(i) Latitude and longitude coordinates, Universal Mercator grid-system coordinates,
state plane coordinates in the Lambert or
Transverse Mercator Projection System;
(ii) Distances in feet from the 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.
(i) Facility dimensions and orientation;
(ii) Elevations relative to Mean Lower Low
Water; and
(iii) Pile sizes and penetration.
The approved for construction fabrication
drawings should be submitted including,
e.g.,
(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.
A summary of the environmental data used in
the design or analysis of the facility. Examples of relevant data include information on:
(i) Extreme weather;
(ii) Seafloor conditions; and
(iii) Waves, wind, current, tides, temperature, snow and ice effects, marine
growth, and water depth.
You must submit 1 paper copy and 1 electronic copy.
(2) Location plat .................................................
(3) Front, Side, and Plan View drawings ...........
(4) Complete set of structural drawings .............
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(5) Summary of environmental data used for
design.
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Your plat must be drawn to a scale of 1 inch
equals 100 feet and include the coordinates
of the lease, ROW grant, or RUE grant
block boundary lines. You must submit 1
paper copy and 1 electronic copy.
Your drawing sizes must not exceed 11″ x
17″. You must submit 1 paper copy and 1
electronic copy.
Your drawing sizes must not exceed 11″ x
17″. You must submit 1 paper copy and 1
electronic copy.
You must submit 1 paper copy and 1 electronic copy. If you submitted these data as
part of your SAP, COP, or GAP, you may
reference the plan.
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Required documents
Required contents
Other requirements
(6) Summary of the engineering design data ....
(i) Loading information (e.g., live, dead, 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).
Self-explanatory ...............................................
You must submit 1 paper copy and 1 electronic copy.
(7) A complete set of design calculations ..........
(8) Project-specific studies used in the facility
design or installation.
(9) Description of the loads imposed on the facility.
(10) Geotechnical Report ...................................
(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 § 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
All studies pertinent to facility design or installation, e.g., oceanographic and soil reports
including the results of the surveys required
in §§ 585.610(b), 585.627(a), or 585.645(a).
(i) Loads imposed by jacket;
(ii) Decks;
(iii) Production components;
(iv) Foundations, foundation pilings and templates, and anchoring systems; and
(v) Mooring or tethering systems.
A list of all data from borings and recommended design parameters.
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 § 585.113.
You must submit 1 paper copy and 1 electronic copy.
You must submit 1 paper copy and 1 electronic copy.
You must submit 1 paper copy and 1 electronic copy.
You must submit 1 paper copy and 1 electronic copy.
§ 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
§ 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 facility designation, lease, ROW
grant, or RUE grant number;
(ii) Area, name, and block number; and
(iii) The type of facility.
Fabrication and installation ..............................
You must submit 1 paper copy and 1 electronic copy.
(2) Schedule .......................................................
(3) Fabrication information .................................
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(4) Installation process information ....................
(5) Federal, State, and local permits (e.g., EPA,
Army Corps of Engineers).
(6) Environmental information ............................
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The industry standards you will use to ensure
the facilities are fabricated to the design criteria identified in your Facility Design Report.
Details associated with the deployment activities, equipment, and materials, including
onshore and offshore equipment and support, and anchoring and mooring patterns.
Either 1 copy of the permit or information on
the status of the application.
(i) Water discharge;
(ii) Waste disposal;
(iii) Vessel information; and
(iv) Onshore waste receiving treatment or disposal facilities.
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You must submit 1 paper copy and 1 electronic copy.
You must submit 1 paper copy and 1 electronic copy.
You must submit 1 paper copy and 1 electronic copy.
You must submit 1 paper copy and 1 electronic copy.
You must submit 1 paper copy and 1 electronic copy. If you submitted these data as
part of your SAP, COP, or GAP, you may
reference the plan.
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Required documents
Required contents
Other requirements
(7) Project easement ..........................................
Design of any cables, pipelines, or facilities.
Information on burial methods and vessels.
You must submit 1 paper copy and 1 electronic copy.
(b) You must provide the location of
records, as required in § 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 asbuilt 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 § 585.113.
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 § 585.714(c).
(c) BOEM may require you to use a
CVA for project modifications and
repairs.
§ 585.704
[Reserved]
Certified Verification Agent
§ 585.703 What reports must I submit for
project modifications and repairs?
§ 585.705 When must I use a Certified
Verification Agent (CVA)?
(a) You must verify and, in a report
to us, certify that major repairs and
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:
You must use a CVA to review and
certify the Facility Design Report, the
Then BOEM may waive the requirement for a CVA for the following:
(1) The facility design conforms to a standard design that has been
used successfully in a similar environment, and the installation design conforms to accepted engineering practices.
(2) The manufacturer has successfully manufactured similar facilities,
and the facility will be fabricated in conformance with accepted engineering practices.
(3) The installation company has successfully installed similar facilities
in a similar offshore environment, and your structure(s) will be installed in conformance with accepted engineering practices.
(4) Repairs and major modifications will be completed in conformance
with accepted engineering practices.
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If you demonstrate that . . .
The design of your 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 § 585.610(a)(9), COP under
§ 585.626(b)(20), or GAP under
§ 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 § 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.
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The fabrication of your structure(s).
The installation of your structure(s).
The repair or major modification of your structure(s).
§ 585.706 How do I nominate a CVA for
BOEM approval?
(a) As part of your COP (as provided
in § 585.626(b)(20) and, when required
by this part, your SAP (§ 585.610(a)(9))
or GAP (§ 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
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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
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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.
§ 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.
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§ 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 § 585.709;
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(4) Make periodic onsite inspections
while installation is in progress and
satisfy the requirements of § 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 § 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.
§ 585.709 When conducting onsite
fabrication inspections, what must the CVA
or project engineer verify?
(a) To comply with § 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 corrosionprotection systems and splash-zone
protection;
(11) Erection procedures to ensure
that overstressing of structural members
does not occur;
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(12) Alignment procedures;
(13) Dimensional check of the overall
structure, including any turrets, turretand-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.
§ 585.710 When conducting onsite
installation inspections, what must the CVA
or project engineer do?
To comply with § 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.
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(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.
§ 585.711
[Reserved]
§ 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.
§ 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.
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§ 585.714 What records relating to SAPs,
COPs, and GAPs must I keep?
(a) Until BOEM releases your
financial assurance under § 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
§§ 585.820 through 585.825; and
(5) Records of repairs not covered in
the inspection report submitted under
§ 585.824(b)(3).
(b) You must record and retain the
original material test results of all
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primary structural materials during all
stages of construction until BOEM
releases your financial assurance under
§ 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
§§ 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
§ 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 § 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 §§ 585.615(c),
585.633(b), or 585.653(c).
§ 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
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64773
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.
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(5) Your agreement to perform any
relevant mitigation measures under an
MMPA incidental take authorization.
for conducting the biological survey and
will specify the contents of the
biological report.
§ 585.814
§ 585.802 What must I do if I discover a
potential archaeological resource while
conducting my approved activities?
§§ 585.804–585.809
§ 585.815 What must I do if I have facility
damage or an equipment failure?
(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 seafloordisturbing 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.
§ 585.810 What must I include in my Safety
Management System?
Safety Management Systems
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§ 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
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[Reserved]
You must submit a description of the
Safety Management System you will use
with your COP (provided under
§ 585.627(d)) and, when required by this
part, your SAP (as provided in
§ 585.614(b)) or GAP (as provided in
§ 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.
§ 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 § 585.810.
§ 585.812
[Reserved]
Maintenance and Shutdowns
§ 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
§ 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.
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[Reserved]
Equipment Failure and Adverse
Environmental Effects
(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 § 585.711.
(b) If you are required to report any
facility damage or failure under
§ 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
§ 585.634 (COP), § 585.617 (SAP),
§ 585.655 (GAP). You must submit a
report of the repairs to BOEM, as
required in § 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.
§ 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.
§§ 585.817–585.819
[Reserved]
Inspections and Assessment
§ 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 § 585.810.
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§ 585.821 Will BOEM conduct scheduled
and unscheduled inspections?
BOEM will conduct both scheduled
and unscheduled inspections.
(3) A summary of the inspection
indicating what repairs, if any, were
needed and the overall structural
condition of the facility.
§ 585.822 What must I do when BOEM
conducts an inspection?
§ 585.825 When must I assess my
facilities?
(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 § 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.
(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 § 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.
§ 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.
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§ 585.824 How must I conduct selfinspections?
(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 abovewater 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
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§§ 585.826–585.829
[Reserved]
Incident Reporting and Investigation
§ 585.830 What are my incident reporting
requirements?
(a) You must report all incidents
listed in § 585.831 to BOEM, according
to the reporting requirements for these
incidents in §§ 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.
§ 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
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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.
§ 585.832 How do I report incidents
requiring immediate notification?
For an incident requiring immediate
notification under § 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.
§ 585.833 What are the reporting
requirements for incidents requiring written
notification?
(a) For any incident covered under
§ 585.831, you must submit a written
report within 15 days after the incident
to BOEM. The report must contain the
following information:
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(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
§ 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.
§ 585.901 When do I accrue
decommissioning obligations?
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You accrue decommissioning
obligations when you are or become a
lessee or grant holder, and you either
install, construct, or acquire by a BOEMapproved assignment a facility, cable, or
pipeline, or you create an obstruction to
other uses of the OCS.
§ 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 § 585.909, within 2 years
following termination of a lease or grant,
you must:
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(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
§ 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 bottomdisturbing 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.
§ 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 § 585.400 of this part.
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§ 585.904 Can I request a departure from
the decommissioning requirements?
You may request a departure from the
decommissioning requirements under
§ 585.103.
Decommissioning Applications
§ 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.
§ 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 § 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
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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.
§ 585.907 How will BOEM process my
decommissioning application?
(a) Based upon your inclusion of all
the information required by § 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.
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§ 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 §§ 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:
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(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
§ 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.
§ 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.
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64777
(b) Within 60 days after you remove
a facility, you must verify to BOEM that
you have cleared the site.
§ 585.911
[Reserved]
Decommissioning Report
§ 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
§ 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 § 585.400.
Subpart J—Rights of Use and
Easement for Energy- and MarineRelated Activities Using Existing OCS
Facilities
Regulated Activities
§ 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.
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(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.
§§ 585.1001–585.1003
[Reserved]
Requesting an Alternate Use RUE
§ 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.
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§ 585.1005
Use RUE?
How do I request an Alternate
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.
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(d) Evidence that you meet the
requirements of § 585.106, as required
by § 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.
§ 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.
§ 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
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competing applicant qualifies to hold a
lease or grant on the OCS, as required
in §§ 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.
§ 585.1008
[Reserved]
§ 585.1009
[Reserved]
Alternate Use RUE Administration
§ 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.
§ 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.
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§ 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.
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§ 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 § 585.107
that the assignee satisfies the
requirements of § 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
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that accrue under an Alternate Use RUE
after the date we approve the
assignment request.
§ 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.
§ 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.
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§ 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.
§ 585.1017
[Reserved]
Decommissioning an Alternate Use
RUE
§ 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.
§ 585.1019 What are the decommissioning
requirements for an Alternate Use RUE?
(a) Decommissioning requirements
will be determined by BOEM on a caseby-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
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Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations
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.
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.
SUBCHAPTER C—APPEALS
PART 590—APPEAL PROCEDURES
§ 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.
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
§ 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.
§ 590.2
Who may appeal?
mstockstill on DSK4VPTVN1PROD with RULES2
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
VerDate Mar<15>2010
16:55 Oct 17, 2011
Jkt 226001
§ 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.
§ 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).
supervisor during the 60-day period
established in § 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 § 590.3.
§ 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 § 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.
§ 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.
§ 590.6 Are informal resolutions
permitted?
Subpart B—[Reserved]
(a) You may seek informal resolution
with the issuing officer’s next level
[FR Doc. 2011–22675 Filed 9–29–11; 12:00 pm]
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]]>Agencies
[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
-----------------------------------------------------------------------
30 CFR Chapter II
-----------------------------------------------------------------------
Bureau of Ocean Energy Management
-----------------------------------------------------------------------
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]]
-----------------------------------------------------------------------
DEPARTMENT OF THE INTERIOR
Bureau of Safety and Environmental Enforcement
30 CFR Chapter II
Bureau of Ocean Energy Management
30 CFR Chapter V
[Docket ID: BOEM-2011-0070]
RIN 1010-AD79
Reorganization of Title 30: Bureaus of Safety and Environmental
Enforcement and Ocean Energy Management
AGENCY: Bureau of Safety and Environmental Enforcement (BSEE);
Interior, Bureau of Ocean Energy Management (BOEM); Interior.
ACTION: Direct final rule.
-----------------------------------------------------------------------
SUMMARY: This rule contains regulations that will be under the
authority of two newly formed Bureaus, the Bureau of Safety and
Environmental Enforcement (BSEE) and the Bureau of Ocean Energy
Management (BOEM), both within the Department of the Interior. On May
19, 2010, the Secretary of the Interior announced the separation of the
responsibilities performed by the Bureau of Ocean Energy Management,
Regulation and Enforcement (BOEMRE) (formerly the Minerals Management
Service) into three new separate organizations: Office of Natural
Resources Revenue (ONRR), Bureau of Ocean Energy Management (BOEM), and
Bureau of Safety and Environmental Enforcement (BSEE). Those
regulations that will apply to the authority of BSEE organization will
remain in 30 CFR chapter II, but be retitled ``Bureau of Safety and
Environmental Enforcement.'' This rule removes from chapter II those
regulations that will apply to the authority of BOEM and recodifies
them into a new 30 CFR chapter V entitled ``Bureau of Ocean Energy
Management.''
DATES: Effective Dates: This rule is effective on October 1, 2011.
FOR FURTHER INFORMATION CONTACT: Kumkum Ray, Regulations and Standards
Branch, (703) 787-1604, e-mail address: kumkum.ray@boemre.gov.
SUPPLEMENTARY INFORMATION:
Background
Order of Events
On May 19, 2010, the Secretary of the Department of the Interior
(Secretary) issued Secretarial Order No. 3299, which announced the
restructuring of the former Minerals Management Service (MMS). The
restructuring divided the responsibilities of the former MMS into three
new bureaus within the Department of the Interior:
(1) Bureau of Ocean Energy Management (BOEM).
(2) Bureau of Safety and Environmental Enforcement (BSEE).
(3) Office of Natural Resources Revenue (ONRR).
On June 18, 2010, the Secretary issued Secretarial Order No. 3302,
which announced the name change of the former MMS to Bureau of Ocean
Energy Management, Regulation and Enforcement (BOEMRE). This name,
BOEMRE, will be in effect until the new organizations are in place
October 1, 2011.
On October 1, 2010, the functions of the former Minerals Revenue
Management (MRM) officially transferred to ONRR, reporting to the
Assistant Secretary for Policy, Management and Budget.
On October 4, 2010, ONRR published a final rule in the Federal
Register (75 FR 61051), moving the regulations related to its royalty
and revenue functions from 30 CFR chapter II to chapter XII.
October 1, 2011 will be the effective date of the separation of the
[remaining components of] BOEMRE into BOEM and BSEE.
Responsibilities
Secretarial Order No. 3299 established the responsibilities for
BOEM, BSEE, and ONRR as follows:
BOEM will be responsible for conventional (e.g., oil and gas) and
renewable energy-related management functions including, but not
limited to, activities involving resource evaluation, planning, and
leasing, environmental science, and environmental analysis.
BSEE will be responsible for safety and environmental enforcement
functions including, but not limited to, the authority to permit
activities, inspect, investigate, summon witnesses and produce
evidence: levy penalties; cancel or suspend activities; and oversee
safety, response and removal preparedness.
ONRR is responsible for royalty and revenue management functions
including, but not limited to, royalty and revenue collection,
distribution, auditing and compliance, investigation and enforcement,
and asset management for both onshore and offshore activities.
Secretarial Order No. 3299 further established that BOEM and BSEE
will be under the supervision of the Assistant Secretary for Land and
Minerals Management (ASLM) and that ONRR will be under the supervision
of the Assistant Secretary for Policy, Management and Budget. This
order also directed the ASLM to ``take appropriate steps to ensure that
this reorganization will provide that agency decisions are made in
compliance with all applicable safety, environmental, and conservation
laws and regulations * * *'' The reorganization of these regulations
supports this directive.
In a January 19, 2011, statement, the Secretary established the
missions and functions of BOEM and BSEE as follows:
BOEM Mission: Responsible for managing development of the
nation's offshore resources in an environmentally and economically
responsible way.
BOEM Functions include: Leasing, Plan Administration,
Environmental Studies, National Environmental Policy Act (NEPA)
Analysis, Resource Evaluation, Economic Analysis, and the Renewable
Energy Program.
BSEE Mission: Enforce safety and environmental
regulations.
BSEE Functions include: All field operations including
Permitting and Research, Inspections, Research, Offshore Regulatory
Programs, Oil Spill Response, and newly formed Training and
Environmental Compliance functions.
Rulemaking Procedure
This rule pertains solely to the organization and codification of
existing rules and related technical changes necessitated by a division
of one agency into two separate agencies. It makes no changes to the
substantive legal rights, obligations, or interests of affected
parties. This rule therefore is a ``rule[] of agency organization,
procedure or practice'' and is therefore exempt from the notice-and-
comment requirements of 5 U.S.C. 553 under 5 U.S.C. 553(b)(A).
Additionally, for the same reasons, BOEMRE finds for good cause shown
that notice and comment on this rule are unnecessary and contrary to
the public interest under 5 U.S.C. 553(b)(B). Because this rule makes
no changes to the legal obligations or rights of non-governmental
entities, the Department further finds that good cause exists under 5
U.S.C. 553(d)(3) to make this rule effective on October 1, 2011, rather
than a full 30 days after publication in the Federal Register.
Proposed Rule
BOEM and BSEE will also jointly issue a proposed rule that will
address some more substantive changes to the regulations. In part, the
proposed rule will address regulatory anomalies created by splitting
the functions of one
[[Page 64433]]
agency into two bureaus. In certain cases, the split necessitated
changing the wording of specific provisions. Rather than changing the
wording in this final rule, we have concluded it is more appropriate to
do so in a proposed rule. The proposed rule changes will be substantial
enough in nature to necessitate public comments and publication of a
Notice of Proposed Rulemaking (NPR).
Reorganization of CFR Title 30
Background Information
This final rule assigns the regulations previously codified under
Title 30 of the Code of Federal Regulations (30 CFR), chapter II--
Minerals Management Service, Department of the Interior, Subchapter A--
Minerals Revenue Management, Subchapter B--Offshore, and Subchapter C--
Appeals; to BSEE, under chapter II and to BOEM, under chapter V. The
assignment of the regulations is based on the responsibilities and
authorities established by Secretarial Order No. 3299, separating BSEE
and BOEM and the January 19, 2011, statement that further clarified
each bureau's mission and functions.
To effectively manage the energy and mineral resources of the Outer
Continental Shelf (OCS), the current regulations must be separated
based on the responsibilities of the new bureaus. Based on the
responsibilities established by Secretarial Order No. 3299, separating
BOEMRE into BOEM and BSEE, this direct final rule reorganizes the
regulations previously found in 30 CFR chapter II by:
1. Retitling chapter II as ``Bureau of Safety and Environmental
Enforcement'';
2. Retaining the regulations that will be under the authority of
BSEE in chapter II;
3. Adding a new chapter, ``Chapter V--Bureau of Ocean Energy
Management''; and
4. Moving the regulations that will be under the authority of BOEM
to 30 CFR chapter V.
In addition to redesignating the regulations to the appropriate
bureau, this rule makes minor supporting edits for clarification,
consistency, or to reiterate current and longstanding practices.
However, the regulatory requirements themselves are not changed. These
edits generally fall under one of the following categories:
Updates to cross-references to reflect the two new sets of
rules, such as:
[cir] Change Sec. 250.101(a) to 550.101(a)),
[cir] Change Sec. 250.123 to 30 CFR 250.123,
[cir] Change ``see Sec. 250.111'' to ``see Sec. 250.111 and 30
CFR 550.111'';
Change references from MMS or BOEMRE to BSEE or BOEM. It
should be understood, however, that references to BSEE or BOEM actions
before October 1, 2011, refer to the predecessor agency (MMS or BOEMRE)
performing the functions specified in the regulations;
Changes in the text to reference new chapter, section, or
title headings;
Correction of spelling or grammatical errors;
Changes of physical and Web site addresses;
Changes of titles, i.e., authorized manager (Regional
Director, Regional Supervisor etc.), and specifying the appropriate
title, based on the bureau (i.e., BSEE Regional Director or BOEM
Regional Director); and/or
Cross-References
This direct final rule is not intended to make any substantive
changes to the regulations or requirements previously set forth in 30
CFR chapter II. In redesignating the regulations, various provisions of
this rule contain cross-references to earlier approvals or other
actions taken under redesignated sections. This rule replaces the
cross-references to previous sections with cross-references to new
sections.
Forms and Information Collection
BOEM and BSEE will rename forms as either BOEM or BSEE forms; MMS
will be removed from the form names. Each form will retain its already
assigned number, except that all numbers will now be four digits. We
will add a zero(s) in front of an existing form number where necessary
(e.g., form MMS-123 will now become form BSEE-0123). The forms
themselves are not changed by this rule.
There are no Information Collection (IC) burden changes in this
rule.
Assignment of Regulations and Explanations
All sections that BSEE retains keep their existing numbers,
reflecting their existing location in 30 CFR chapter II. BOEM citations
are renumbered using the number ``5'' as the first number for the part,
reflecting their new location in 30 CFR chapter V.
The following table (Table A) provides an overview of the
assignment of regulations between BOEM and BSEE, by part. Many parts
are retained in their entirety by BSEE or moved in their entirety to
BOEM. Additional details of how other parts are divided between the two
bureaus follow in Tables B through O.
Table A--Derivation Table
Title 30--Mineral Resources
Chapter II--Bureau of Ocean Energy Management, Regulation and
Enforcement
------------------------------------------------------------------------
Current part New location Justification
------------------------------------------------------------------------
Subchapter A--Minerals Revenue Management
------------------------------------------------------------------------
Part 203--Relief or Reduction Retained in its BSEE will oversee the
in Royalty Rates. entirety in administration of
BSEE, chapter II. royalty relief
awarded after lease
issuance as an
operational
responsibility.
However, BOEM will
set the terms and
conditions of any
future leases issued
with royalty relief
provisions.
Part 219--Distribution and Moved in its BOEM will perform
Disbursement of Royalties, entirety to revenue share
Rentals, and Bonuses. BOEM, chapter V, calculations for
part 519. Outer Continental
Shelf (OCS) receipts
shared under the
Gulf of Mexico
Energy Security Act
(GOMESA). ONRR will
continue to
distribute the
revenue shares to
Gulf producing
States and Coastal
Political
Subdivisions.
------------------------------------------------------------------------
Subchapter B--Offshore
------------------------------------------------------------------------
Part 250--Oil and Gas and Responsibilities Both bureaus have
Sulphur Operations in the divided between responsibilities
Outer Continental Shelf. BOEM and BSEE. that are related to
operations on OCS
leases. These
responsibilities
were divided between
the two bureaus as
detailed in Table B.
[[Page 64434]]
Part 251--Geological and Responsibilities BOEM will be
Geophysical (G&G) divided between responsible for
Explorations of the Outer BOEM and BSEE. issuing the permits
Continental Shelf. and notices and
overseeing the
activities under the
approved permit, as
these are prelease,
resource assessment-
related activities.
BSEE will be
responsible for
issuing permits for
test drilling
activities under
their
responsibilities for
operations. Further
details are provided
in Table C.
Part 252--Outer Continental Both BOEM and Part 252 regulates
Shelf (OCS) Oil and Gas BSEE will have how and when the
Information Program. this part in its date and information
entirety. is released by the
OCS Oil and Gas
Information Program.
Since both bureaus
will collect,
maintain, and use
data and information
collected under this
program, both are
responsible for
managing the data
and determining how
and when the data
and information are
released. Further
details are provided
in Table D.
Part 253--Oil Spill Financial Moved to BOEM in BOEM is responsible
Responsibility for Offshore its entirety, for all activities
Facilities. chapter V, part related to financial
553. assurance. Oil spill
financial
responsibility
requirements are
mandated by the Oil
Pollution Act of
1990 (OPA) that
applies to oil
handling activities
at any offshore
facility (whether or
not involved in oil
production) seaward
of the coastline.
Further details are
provided in Table E.
Part 254--Oil-Spill Response Retained in its All oil-spill related
Requirements for Facilities entirety in BSEE. activities, except
Located Seaward of the Coast for financial
Line. responsibility, will
fall under BSEE,
under its
responsibility for
oil-spill response.
Further details are
provided in Table F.
Part 256--Leasing of Sulphur Responsibilities BOEM has primary
or Oil and Gas in the Outer divided between responsibility for
Continental Shelf. BOEM and BSEE. leasing and leasing-
related activities.
Some
responsibilities
related to
operations and
production will be
in both bureaus.
Suspension-related
requirements will go
to BSEE. Further
details are provided
in Table G.
Part 259--Mineral Leasing: Moved to BOEM in BOEM is responsible
Definitions. its entirety, for leasing
chapter V, part activities. Further
559. details are provided
in Table H.
Part 260--Outer Continental Moved to BOEM in BOEM is responsible
Shelf Oil and Gas Leasing. its entirety, for leasing
chapter V, part activities. Further
560. details are provided
in Table I.
Part 270--Nondiscrimination in Both BOEM and Both BOEM and BSEE
the Outer Continental Shelf. BSEE will have are responsible for
this part in its ensuring that
entirety. lessees and
operators comply
with section 604 of
the OCSLA of 1978,
which provides that
``no person shall,
on the grounds of
race, creed, color,
national origin, or
sex, be excluded
from receiving or
participating in any
activity, sale, or
employment,
conducted pursuant
to the provisions of
. . . the Outer
Continental Shelf
Lands Act.'' Further
details are provided
in Table J.
Part 280--Prospecting for Moved to BOEM in This part regulates
Minerals Other Than Oil, Gas, its entirety, prospecting
and Sulphur on the Outer chapter V, part activities or
Continental Shelf. 580. scientific research
activities on the
OCS in Federal
waters related to
hard minerals on
unleased lands or on
lands under lease to
a third party. These
activities fall
under BOEM
responsibilities for
managing the
development of
offshore resources
and activities on
unleased land or on
lands leased to a
third party. Further
details are provided
in Table K.
Part 281--Leasing of Minerals Moved to BOEM in This part regulates
Other Than Oil, Gas, and its entirety, leasing for minerals
Sulphur in the Outer chapter V, part other than oil, gas,
Continental Shelf. 581. and sulphur in the
OCS. Leasing
activities are a
BOEM responsibility.
Further details are
provided in Table L.
Part 282--Operations in the Responsibilities Both BOEM and BSEE
Outer Continental Shelf for divided between have
Minerals Other Than Oil, Gas, BOEM and BSEE. responsibilities for
and Sulphur. operations conducted
under a mineral
lease for OCS
minerals other than
oil, gas, or
sulphur. These
responsibilities
were divided between
the two bureaus as
detailed in Table M.
Part 285--Renewable Energy and Moved in its At this time, the
Alternate Uses of Existing entirety to renewable energy
Facilities on the Outer BOEM, chapter V, program will be
Continental Shelf. part 585. managed under BOEM.
At a later date, the
renewable energy
program will be
reorganized and a
determination will
be made regarding
what functions will
be administered by
which agency.
------------------------------------------------------------------------
Subchapter C--Appeals
------------------------------------------------------------------------
Part 290--Appeal Procedures... Both BOEM and Appeal procedures
BSEE will have apply to decisions
this part in its and orders issued by
entirety. both BOEM and BSEE.
Further details are
provided in Table O.
Part 291--Open and Retained in its This part deals with
Nondiscriminatory Access to entirety in BSEE. access to pipelines.
Oil and Gas Pipelines under All aspects of
the Outer Continental Shelf pipelines, including
Lands Act. operations are under
the responsibility
of BSEE. Further
details are provided
in Table P.
------------------------------------------------------------------------
[[Page 64435]]
The reorganization of the individual parts and subparts is as
follows:
Subchapter A--Minerals Revenue Management
Part 203--Relief or Reduction in Royalty Rates--Retained in Its
Entirety in BSEE, Chapter II
BSEE is responsible for the regulatory oversight of need-based
royalty relief awarded after lease issuance and the tracking of all
royalty-free production.
Part 219--Distribution and Disbursement of Royalties, Rentals, and
Bonuses--Moved in Its Entirety to BOEM, Chapter V, Part 519
BOEM will perform revenue share calculations for OCS receipts
shared under GOMESA.
Subchapter B--Offshore
Part 250--Oil and Gas and Sulphur Operations in the Outer Continental
Shelf
Part 250 established the requirements for offshore oil, natural
gas, and sulphur operations. These operations include activities after
the lease is established. Most of current Part 250 will stay under
BSEE, with some sections going to BOEM. The details of this division
are as follows.
Table B--Detailed Table for Part 250
------------------------------------------------------------------------
Implementing
Current citation and BSEE bureau and BOEM
citation (if applicable) citation (if Explanation
applicable)
------------------------------------------------------------------------
Subpart A--General
This subpart establishes the basic regulations for oil, gas, and sulphur
exploration, development, and production operations in the OCS. Many of
the requirements in this subpart represent joint responsibilities;
therefore, they belong in both bureaus. Other requirements are the sole
responsibility of one bureau.
------------------------------------------------------------------------
Sec. 250.101 Authority and Both BSEE and Establishes authority
applicability. BOEM, Sec. for the entire part,
550.101. allowing both
bureaus to have some
authority for
operations in the
OCS and both bureaus
need to establish
their authority.
This section also
establishes the
basic requirements
for OCS oil, gas,
and sulphur
operations.
Sec. 250.102 What does this Both BSEE and This section
part do?. BOEM, Sec. describes the
550.102. purpose of these
regulations (parts
250 and 550) and
provides a reference
table addressing
where to find
information for
conducting OCS
operations; it is
applicable to the
regulations in both
bureaus.
Sec. 250.103 Where can I Both BSEE and This section
find more information about BOEM, Sec. establishes the
the requirements in this 550.103. authority for the
part? bureaus to issue
additional guidance
to lessees and
operators, in the
form of Notices to
Lessees and
Operators (NTLs),
and establishes the
expectation of the
lessees and
operators to respond
to that guidance.
Sec. 250.104 How may I Both BSEE and This section explains
appeal a decision made under BOEM, Sec. how a lessee or
MMS regulations? 550.104. operator may appeal
a decision made by
either BSEE or BOEM,
it is informational
and important to
include in both sets
of regulations.
Sec. 250.105 Definitions.... Both BSEE and This section contains
BOEM, Sec. the definitions used
550.105. in parts 250 and
550, the same
definitions will
apply to both sets
of regulations.
Sec. 250.106 What standards Retained by BSEE. This section defines
will the Director use to the standards for
regulate lease operations? performance that
BSEE will use to
regulate lease
operations, these
operations fall
under the authority
of BSEE.
Sec. 250.107 What must I do Retained by BSEE. This section
to protect health, safety, establishes the
property, and the expectations for
environment? operators to protect
health, safety, and
the environment,
these
responsibilities
fall under the
authority of BSEE.
Sec. 250.108 What Retained by BSEE. Addresses cranes and
requirements must I follow other material-
for cranes and other material- handling equipment,
handling equipment? which is related to
an offshore
operation that is
under the authority
of BSEE.
Sec. 250.109 What documents Retained by BSEE. These sections
must I prepare and maintain address welding
related to welding? requirements, which
are related to
offshore operations
that are under the
authority of BSEE.
Sec. 250.110 What must I
include in my welding plan?
Sec. 250.111 Who oversees
operations under my welding
plan?
Sec. 250.112 What standards
must my welding equipment
meet?
Sec. 250.113 What procedures
must I follow when welding?
Sec. 250.114 How must I Retained by BSEE. Addresses the
install and operate installation and
electrical equipment? operation of
electrical
equipment, which are
related to offshore
operations that are
under the authority
of BSEE.
Sec. 250.115 How do I Moved to BOEM, Addresses well
determine well producibility? Sec. Sec. producibility that
550.115, is under the
550.116, and authority of BOEM.
550.117.
Sec. 250.116 How do I
determine producibility if my
well is in the Gulf of
Mexico?
Sec. 250.117 How does a
determination of well
producibility affect royalty
status?
Sec. 250.118 Will MMS Retained by BSEE. Addresses gas
approve gas injection? injection operations
that are under the
authority of BSEE.
[[Page 64436]]
Sec. 250.119 Will MMS Moved to BOEM, Addresses subsurface
approve subsurface gas Sec. 550.119. gas storage that is
storage? under the authority
of BOEM.
Sec. 250.120 How does Retained by BSE.. These pertain to gas
injecting, storing, or storage operations
treating gas affect my that are under the
royalty payments? authority of BSEE.
Sec. 250.121 What happens
when the reservoir contains
both original gas in place
and injected gas?
Sec. 250.122 What effect Both BSEE and This section
does subsurface storage have BOEM Sec. clarifies that an
on the lease term? 550.122. approved storage
project has no
effect on lease
term.
Sec. 250.123 Will MMS allow Moved to BOEM, This section allows
gas storage on unleased Sec. 550.123. gas storage on
lands? unleased lands,
through a right-of-
use and easement
(RUE). RUEs are
issued by BOEM,
under their
responsibility for
resource management.
Sec. 250.124 Will MMS Retained by BSEE. This section
approve gas injection into addresses gas
the cap rock containing a injection
sulphur deposit? operations.
Offshore operations
are under the
authority of BSEE.
Sec. 250.125 Service fees... Both BSEE and Both BSEE and BOEM
BOEM, Sec. will oversee
550.125. activities that
require collection
of a service fee.
Sec. 250.126 Electronic Both BSEE and Provides information
payment instructions. BOEM, Sec. on how to pay the
550.126. fees collected by
BSEE and BOEM.
Sec. 250.130 Why does MMS Retained by BSEE. BSEE will be
conduct inspections? responsible for
issuing permits and
notices and
inspecting the
operations under
approved leases,
plans, and permit.
Sec. 250.131 Will MMS notify Retained by BSEE. BSEE will be
me before conducting an responsible for
inspection? inspecting
operations and
activities on the
OCS.
Sec. 250.132 What must I do
when MMS conducts an
inspection?
Sec. 250.133 Will MMS
reimburse me for my expenses
related to inspections?
Sec. 250.135 What will MMS Both BSEE and BSEE is responsible
do if my operating BOEM, Sec. Sec. for finding operator
performance is unacceptable? 550.135 and performance
550.136. unacceptable under
the criteria of Sec.
550.136, but the
final adjudication
is a BOEM action.
Sec. 250.136 How will MMS
determine if my operating
performance is unacceptable?
Sec. 250.140 When will I Both BSEE and Both BSEE and BOEM
receive an oral approval? BOEM, Sec. may grant verbal
550.140, except approvals for
for paragraph activities and
(c), which will operations under
remain with BSEE their respective
only. authorities.
Paragraph (c)
addresses oral
approvals for gas
flaring that will be
regulated only by
BSEE.
Sec. 250.141 May I ever use Both BSEE and This section explains
alternate procedures or BOEM, Sec. how a lessee or
equipment? 550.141. operator may request
to use alternate
procedures or
equipment that is
not addressed in
current regulations.
It is informational
and important to
include in both sets
of regulations.
Sec. 250.142 How do I Both BSEE and This section provides
receive approval for BOEM, Sec. information on how a
departures? 550.142. lessee or operator
can request a
departure from the
applicable BSEE or
BOEM regulations.
BSEE and BOEM may
grant departures for
activities and
operations under the
respective
authorities.
Sec. 250.143 How do I Moved to BOEM, This section
designate an operator? Sec. 550.143. addresses the
designation of an
operator that is
under the authority
of BOEM.
Sec. 250.144 How do I Moved to BOEM, This section
designate a new operator when Sec. 550.144. addresses the
a designation of operator designation of an
terminates? operator that is
under the authority
of BOEM.
Sec. 250.145 How do I Both BSEE and This section
designate an agent or a local BOEM, Sec. addresses the
agent? 550.145. designation of an
agent that is under
the authority of
both BSEE and BOEM.
Sec. 250.146 Who is Both BSEE and This section provides
responsible for fulfilling BOEM, Sec. information on who
leasehold obligations? 550.146. is responsible for
fulfilling leasehold
obligations. These
activities are
conducted under the
authority of both
BSEE and BOEM.
Sec. 250.150 How do I name Retained by BSEE. This section provides
facilities and wells in the information on
Gulf of Mexico Region? naming facilities
and wells in the
Gulf of Mexico
region that is under
the authority of
BSEE.
Sec. 250.151 How do I name Retained by BSEE. This section provides
facilities in the Pacific information on
Region? naming facilities
and wells in the
Pacific region that
are under the
authority of BSEE.
Sec. 250.152 How do I name Retained by BSEE. This section provides
facilities in the Alaska information on
Region? naming facilities
and wells in the
Alaska region that
are under the
authority of BSEE.
Sec. 250.153 Do I have to Retained by BSEE. This section provides
rename an existing facility information on
or well? renaming existing
facilities and wells
that are under the
authority of BSEE.
Sec. 250.154 What Retained by BSEE. This section provides
identification signs must I information on the
display? required
identification signs
that must be
displayed that are
under the authority
of BSEE.
[[Page 64437]]
Sec. 250.160 When will MMS Moved to BOEM, This section provides
grant me a right-of-use and Sec. 550.160. information on the
easement, and what requirements that
requirements must I meet? must be met to
obtain a RUE. RUEs
are issued by BOEM
under their
responsibility for
resource management.
Sec. 250.161 What else must Moved to BOEM, This section provides
I submit with my application? Sec. 550.161. information on
additional
requirements that
must be contained in
the RUE application.
RUEs are issued by
BOEM under their
responsibility for
resource management.
Sec. 250.162 May I continue Moved to BOEM, This section provides
my right-of-use and easement Sec. 550.162. information on RUEs
after the termination of any that are issued by
lease on which it is BOEM under their
situated? responsibility for
resource management.
Sec. 250.163 If I have a Moved to BOEM, This section concerns
State lease, will MMS grant Sec. 550.163. RUEs that are issued
me a right-of-use and by BOEM under their
easement? responsibility for
resource management.
Sec. 250.164 If I have a Moved to BOEM, This section provides
State lease, what conditions Sec. 550.164. information on RUEs
apply for a right-of-use and that are issued by
easement? BOEM under their
responsibility for
resource management.
Sec. 250.165 If I have a Moved to BOEM, This section provides
State lease, what fees do I Sec. 550.165. information on RUEs
have to pay for a right-of- that are issued by
use and easement? BOEM under their
responsibility for
resource management.
Sec. 250.166 If I have a Moved to BOEM, This section provides
State lease, what surety bond Sec. 550.166. information on RUEs
must I have for a right-of- that are issued by
use and easement? BOEM under their
responsibility for
resource management.
Sec. 250.168 May operations Retained by BSEE. These sections
or production be suspended? address suspension
of operations or
production. Offshore
operations are under
the authority of
BSEE.
Sec. 250.169 What effect
does suspension have on my
lease?
Sec. 250.170 How long does a
suspension last?
Sec. 250.171 How do I
request a suspension?
Sec. 250.172 When may the Retained by BSEE. These sections
Regional Supervisor grant or address suspension
direct an SOO or SOP? of operations or
production. Offshore
operations are under
the authority of
BSEE.
Sec. 250.173 When may the Retained by BSEE.
Regional Supervisor direct an
SOO or SOP?
Sec. 250.174 When may the Retained by BSEE.
Regional Supervisor grant or
direct an SOP?
Sec. 250.175 When may the Retained by BSEE. This section
Regional Supervisor grant an addresses suspension
SOO? of operations.
Offshore operations
are under the
authority of BSEE.
Sec. 250.176 Does a Retained by BSEE. These sections
suspension affect my royalty address suspension
payment? of operations or
production. Offshore
operations are under
the authority of
BSEE.
Sec. 250.177 What additional
requirements may the Regional
Supervisor order for a
suspension?
Sec. 250.180 What am I Retained by BSEE. This section
required to do to keep my addresses
lease term in effect? requirements for
keeping a lease term
in effect. BSEE will
determine if a lease
meets these
requirements.
Sec. 250.181 When may the Moved to BOEM, This section
Secretary cancel my lease and Sec. 550.181. addresses lease
when am I compensated for cancellations.
cancellation? Offshore lease
administration is
under the authority
of BOEM. Past the
primary lease term,
BSEE has greater
authority over lease
extensions via
operations or
suspensions; BOEM
continues its lease
administration
function.
Sec. 250.182 When may the Moved to BOEM, This section
Secretary cancel a lease at Sec. 550.182. addresses lease
the exploration stage? cancellations.
Offshore lease
administration,
including lease
terms, is under the
authority of BOEM.
Past the primary
lease term, BSEE has
greater authority
over lease
extensions via
operations or
suspensions; BOEM
continues its lease
administration
function.
Sec. 250.183 When may MMS or Moved to BOEM, This section
the Secretary extend or Sec. 550.183. addresses lease
cancel a lease at the cancellations.
development and production Offshore lease
stage? administration, is
under the authority
of BOEM. Past the
primary lease term,
BSEE has greater
authority over lease
extensions via
operations or
suspensions; BOEM
continues its lease
administration
function.
Sec. 250.184 What is the Moved to BOEM, This section
amount of compensation for Sec. 550.184. addresses lease
lease cancellation? cancellations.
Offshore lease
administration,
including lease
terms, is under the
authority of BOEM.
Sec. 250.185 When is there Moved to BOEM, This section
no compensation for a lease Sec. 550.185. addresses lease
cancellation? cancellations.
Offshore lease
administration,
including lease
terms, is under the
authority of BOEM.
[[Page 64438]]
Sec. 250.186 What reporting Both BSEE and This section provides
information and report forms BOEM, Sec. information
must I submit? 550.186. concerning reporting
requirements and
form submission This
information is
applicable to both
BSEE and BOEM
activities.
Sec. 250.187 What are MMS' Retained by BSEE. This section
incident reporting addresses incident
requirements? reporting
requirements for
offshore operations
that are under the
authority of BSEE.
Sec. 250.188 What incidents Retained by BSEE. This section
must I report to MMS and when addresses incident
must I report them? reporting
requirements for
offshore operations
that are under the
authority of BSEE.
Sec. 250.189 Reporting Retained by BSEE. This section
requirements for incidents addresses incident
requiring immediate reporting
notification. requirements for
offshore operations
that are under the
authority of BSEE.
Sec. 250.190 Reporting Retained by BSEE. This section
requirements for incidents addresses incident
requiring written reporting
notification. requirements for
offshore operations
that are under the
authority of BSEE.
Sec. 250.191 How does MMS Retained by BSEE. This section
conduct incident addresses incident
investigations? investigations for
offshore operations
that are under the
authority of BSEE.
Sec. 250.192 What reports Retained by BSEE. This section requires
and statistics must I submit operators to submit
relating to a hurricane, information relating
earthquake, or other natural to the impact of
occurrence? hurricanes on on-
going offshore
operations, which
are
