### 64432 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**

**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 andStandards Branch, (703) 787–1604, email 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 tothe 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


### 64433 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 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, variousprovisions of this rule contain crossreferences to earlier approvals or other actions taken under redesignatedsections. 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—D ERIVATION 

### 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 in

Royalty Rates. Retained in its entirety in BSEE, chapter II. 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.

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 Outer ContinentalShelf (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. Responsibilities divided between
BOEM and BSEE. 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—D ERIVATION 

### 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. BOEM will be responsible for issuing the permits and notices and overseeing the activities under the approved permit, as these areprelease, 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 Shelf

(OCS) Oil and Gas Information Program. Both BOEM and BSEE will have this part in its entirety. Part 252 regulates how and when the date and information is released by the OCS Oil and Gas Information Program. Since bothbureaus 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 Responsibility for Offshore Facilities. Moved to BOEM in its entirety, chapter V, part 553. 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.Part 254—Oil-Spill Response Requirements for Facilities Located

Seaward of the Coast Line. Retained in its entirety in BSEE .... 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. Part 256—Leasing of Sulphur or Oil

and Gas in the Outer Continental

Shelf. Responsibilities divided between
BOEM and BSEE. 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.Part 259—Mineral Leasing: Definitions. Moved to BOEM in its entirety, chapter V, part 559. BOEM is responsible for leasing activities. Further details are provided in Table H.
Part 260—Outer Continental Shelf

Oil and Gas Leasing. Moved to BOEM in its entirety, chapter V, part 560. BOEM is responsible for leasing activities. Further details are provided in Table I.

Part 270—Nondiscrimination in the

Outer Continental Shelf. Both BOEM and BSEE will have this part in its entirety. 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 tothe provisions of . . . the Outer Continental Shelf Lands Act.’’ Further details are provided in Table J. 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. 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. 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. 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.

Part 282—Operations in the Outer

Continental Shelf for MineralsOther Than Oil, Gas, and Sulphur. Responsibilities divided between
BOEM and BSEE. Both BOEM and BSEE have responsibilities for operations conductedunder 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

Alternate Uses of Existing Facilities on the Outer Continental

Shelf. Moved in its entirety to BOEM, chapter V, part 585. At this time, the renewable energy program will be managed underBOEM. 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 BSEE will have this part in its entirety. Appeal procedures apply to decisions and orders issued by both BOEM and BSEE. Further details are provided in Table O.Part 291—Open and Nondiscriminatory Access to Oil and GasPipelines under the Outer Continental Shelf Lands Act. Retained in its entirety in BSEE .... 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.


### 64435 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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 

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### 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 Authority and applicability. Both BSEE and BOEM, § 550.101 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. § 250.102 What does this part do? Both BSEE and BOEM, § 550.102 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. § 250.103 Where can I find more

information about the requirements in this part? Both BSEE and BOEM, § 550.103 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. § 250.104 How may I appeal a

decision made under MMS regulations? Both BSEE and BOEM, § 550.104 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. § 250.105 Definitions .................... Both BSEE and BOEM, § 550.105 This section contains the definitions used in parts 250 and 550, the same definitions will apply to both sets of regulations. § 250.106 What standards will the

Director use to regulate lease operations? Retained by BSEE ......................... This section defines the standards for performance that BSEE will use to regulate lease operations, these operations fall under the authority of BSEE.§ 250.107 What must I do to protect health, safety, property, and

the environment? Retained by BSEE ......................... This section establishes the expectations for operators to protect health, safety, and the environment, these responsibilities fall under the authority of BSEE. § 250.108 What requirements

must I follow for cranes and other material-handling equipment? Retained by BSEE ......................... Addresses cranes and other material-handling equipment, which is related to an offshore operation that is under the authority of

BSEE. § 250.109 What documents must I

prepare and maintain related to welding? Retained by BSEE ......................... These sections address welding requirements, which are related to offshore operations that are under the authority of BSEE.

§ 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 ......................... Addresses the installation and operation of electrical equipment,which are related to offshore operations that are under the authority of BSEE. § 250.115 How do I determine

well producibility? Moved to BOEM, §§ 550.115, 550.116, and 550.117. Addresses well producibility that is under the authority of BOEM.

§ 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? Retained by BSEE ......................... Addresses gas injection operations that are under the authority of

BSEE.


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### 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? Moved to BOEM, § 550.119 .......... Addresses subsurface gas storage that is under the authority of

BOEM. § 250.120 How does injecting,

storing, or treating gas affect my royalty payments? Retained by BSE ........................... These pertain to gas storage operations that are under the authority

of BSEE.

§ 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? Both BSEE and BOEM § 550.122 This section clarifies that an approved storage project has no effect

on lease term.

§ 250.123 Will MMS allow gas

storage on unleased lands? Moved to BOEM, § 550.123 .......... 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. § 250.124 Will MMS approve gas

injection into the cap rock containing a sulphur deposit? Retained by BSEE ......................... This section addresses gas injection operations. Offshore operations are under the authority of BSEE.

§ 250.125 Service fees ................. Both BSEE and BOEM, § 550.125 Both BSEE and BOEM will oversee activities that require collection of

a service fee.§ 250.126 Electronic payment instructions. Both BSEE and BOEM, § 550.126 Provides information on how to pay the fees collected by BSEE and

BOEM.§ 250.130 Why does MMS conduct inspections? Retained by BSEE ......................... BSEE will be responsible for issuing permits and notices and inspecting the operations under approved leases, plans, and permit.§ 250.131 Will MMS notify me before conducting an inspection? Retained by BSEE ......................... BSEE will be responsible for inspecting operations and activities on

the OCS. § 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? 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.§ 250.136 How will MMS determine if my operating performance is unacceptable? § 250.140 When will I receive an

oral approval? 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 andoperations under their respective authorities. Paragraph (c) addresses oral approvals for gas flaring that will be regulated only by

BSEE.§ 250.141 May I ever use alternate procedures or equipment? Both BSEE and BOEM, § 550.141 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.§ 250.142 How do I receive approval for departures? Both BSEE and BOEM, § 550.142 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. § 250.143 How do I designate an

operator? Moved to BOEM, § 550.143 .......... This section addresses the designation of an operator that is under the authority of BOEM. § 250.144 How do I designate a

new operator when a designation of operator terminates? Moved to BOEM, § 550.144 .......... This section addresses the designation of an operator that is under the authority of BOEM.

§ 250.145 How do I designate an

agent or a local agent? Both BSEE and BOEM, § 550.145 This section addresses the designation of an agent that is under the authority of both BSEE and BOEM. § 250.146 Who is responsible for

fulfilling leasehold obligations? Both BSEE and BOEM, § 550.146 This section provides information on who is responsible for fulfillingleasehold obligations. These activities are conducted under the authority of both BSEE and BOEM. § 250.150 How do I name facilities

and wells in the Gulf of Mexico Region? Retained by BSEE ......................... This section provides information on naming facilities and wells in the Gulf of Mexico region that is under the authority of BSEE.

§ 250.151 How do I name facilities

in the Pacific Region? Retained by BSEE ......................... This section provides information on naming facilities and wells in the Pacific region that are under the authority of BSEE. § 250.152 How do I name facilities

in the Alaska Region? Retained by BSEE ......................... This section provides information on naming facilities and wells in the Alaska region that are under the authority of BSEE. § 250.153 Do I have to rename an

existing facility or well? Retained by BSEE ......................... This section provides information on renaming existing facilities and wells that are under the authority of BSEE. § 250.154 What identification

signs must I display? Retained by 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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### 250—Continued

Current citation and BSEE citation (if applicable) 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? Moved to BOEM, § 550.160 .......... This section provides information on the requirements that must bemet to obtain a RUE. RUEs are issued by BOEM under their responsibility for resource management.

§ 250.161 What else must I submit with my application? Moved to BOEM, § 550.161 .......... 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. § 250.162 May I continue my

right-of-use and easement after the termination of any lease on

which it is situated? Moved to BOEM, § 550.162 .......... This section provides information on RUEs that are issued by BOEM under their responsibility for resource management.

§ 250.163 If I have a State lease,

will MMS grant me a right-of-use

and easement? Moved to BOEM, § 550.163 .......... This section concerns RUEs that are issued by BOEM under their responsibility for resource management.

§ 250.164 If I have a State lease,

what conditions apply for a rightof-use and easement? Moved to BOEM, § 550.164 .......... This section provides information on RUEs that are issued by BOEM under their responsibility for resource management.

§ 250.165 If I have a State lease,

what fees do I have to pay for a right-of-use and easement? Moved to BOEM, § 550.165 .......... This section provides information on RUEs that are issued by BOEM under their responsibility for resource management.

§ 250.166 If I have a State lease,

what surety bond must I have for a right-of-use and easement? Moved to BOEM, § 550.166 .......... This section provides information on RUEs that are issued by BOEM under their responsibility for resource management.

§ 250.168 May operations or production be suspended? Retained by BSEE ......................... These sections address suspension of operations or production. Offshore operations are under the authority of BSEE.§ 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? Retained by BSEE ......................... These sections address suspension of operations or production. Offshore operations are under the authority of BSEE.

§ 250.173 When may the Regional Supervisor direct an SOO

or SOP? Retained by BSEE.

§ 250.174 When may the Regional Supervisor grant or direct

an SOP? Retained by BSEE.

§ 250.175 When may the Regional Supervisor grant an SOO? Retained by BSEE ......................... This section addresses suspension of operations. Offshore operations are under the authority of BSEE.§ 250.176 Does a suspension affect my royalty payment? Retained by BSEE ......................... These sections address suspension of operations or production. Offshore operations are under the authority of BSEE.§ 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? Retained by BSEE ......................... This section addresses requirements for keeping a lease term in effect. BSEE will determine if a lease meets these requirements.

§ 250.181 When may the Secretary cancel my lease and whenam I compensated for cancellation? Moved to BOEM, § 550.181 .......... This section addresses lease cancellations. Offshore lease administration is under the authority of BOEM. Past the primary leaseterm, BSEE has greater authority over lease extensions via operations or suspensions; BOEM continues its lease administration

function.§ 250.182 When may the Secretary cancel a lease at the exploration stage? Moved to BOEM, § 550.182 .......... This section addresses lease cancellations. Offshore lease administration, including lease terms, is under the authority of BOEM. Pastthe primary lease term, BSEE has greater authority over lease extensions via operations or suspensions; BOEM continues its lease

administration function. § 250.183 When may MMS or the

Secretary extend or cancel a lease at the development and production stage? Moved to BOEM, § 550.183 .......... This section addresses lease cancellations. Offshore lease administration, is under the authority of BOEM. Past the primary leaseterm, BSEE has greater authority over lease extensions via operations or suspensions; BOEM continues its lease administration

function. § 250.184 What is the amount of

compensation for lease cancellation? Moved to BOEM, § 550.184 .......... This section addresses lease cancellations. Offshore lease administration, including lease terms, is under the authority of BOEM.

§ 250.185 When is there no compensation for a lease cancellation? Moved to BOEM, § 550.185 .......... This section addresses lease cancellations. Offshore lease administration, including lease terms, is under the authority of BOEM.


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### 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? 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. § 250.187 What are MMS’ incident

reporting requirements? Retained by BSEE ......................... This section addresses incident reporting requirements for offshore operations that are under the authority of BSEE. § 250.188 What incidents must I

report to MMS and when must I report them? Retained by BSEE ......................... This section addresses incident reporting requirements for offshore operations that are under the authority of BSEE.

§ 250.189 Reporting requirements

for incidents requiring immediate

notification. Retained by BSEE ......................... This section addresses incident reporting requirements for offshore operations that are under the authority of BSEE.

§ 250.190 Reporting requirements

for incidents requiring written notification. Retained by BSEE ......................... This section addresses incident reporting requirements for offshore operations that are under the authority of BSEE.

§ 250.191 How does MMS conduct incident investigations? Retained by BSEE ......................... This section addresses incident investigations for offshore operations that are under the authority of BSEE.§ 250.192 What reports and statistics must I submit relating to a hurricane, earthquake, or other

natural occurrence? Retained by 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.

§ 250.193 Reports and investigations of apparent violations. Retained by BSEE ......................... This section addresses incident reporting requirements for offshore operations that are under the authority of BSEE.§ 250.194 How must I protect archaeological resources? Moved to BOEM, paragraph (c) retained by BSEE and also in

BOEM with cross reference. 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. § 250.195 What notification does

MMS require on the production

status of wells? Retained by BSEE ......................... 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.§ 250.196 Reimbursements for reproduction and processing costs. Both BSEE and BOEM, § 550.196 Data and information may be requested by either BSEE or BOEM.

§ 250.197 Data and information to

be made available to the public or for limited inspection. BOEM—Introductory paragraph and paragraphs (a)(6), (9), (10), (b), (c)(4), (5), and (6). Both BSEE and BOEM will collect and be responsible for various types of information. This section describes when the informationcollected will be made available to the public and what data and information will be made available for limited inspection. The section was divided based on the type of data and information addressed in each paragraph. BSEE—Introductory paragraph

and paragraphs (a)(1) through (5), (7), (8), (b), (c)(1) through (5) and (7) retained in BSEE.§ 250.198 Documents incorporated by reference. Retained by BSEE ......................... This section addresses documents incorporated by reference and pertains to both BSEE and BOEM activities—e.g. Renewable Energy in BOEM. § 250.199 Paperwork Reduction

Act statements—information collection. Both BSEE and BOEM, § 550.199 This section addresses the Paperwork Reduction Act that is applicable to both BSEE and BOEM.

**Subpart B—Plans and Information**

The plans function, which includes approving Exploration Plans and Development and Production Plans, falls under the jurisdiction of BOEM,

under its authority to manage development of the Nation’s offshore resources in an environmentally and economically responsible way. Therefore, most of Subpart B is being moved to BOEM. BSEE is responsible for Deepwater Operations Plans (DWOPs).

§ 250.200 Definitions .................... Both BSEE and BOEM, § 550.200 Definitions section, the same definitions apply to both bureaus.§ 250.201 What plans and information must I submit before I conduct any activities on my

lease or unit? Both BSEE and BOEM, § 550.201 This section addresses plans that are the responsibility of BOEM. BSEE is responsible for DWOPs.

§ 250.202 What criteria must the

Exploration Plan (EP), Development and Production Plan (DPP),or Development Operations Coordination Document (DOCD)

meet? Moved to BOEM, § 550.202 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.203 Where can wells be located under an EP, DPP, or
DOCD? Moved to BOEM, § 550.203 .......... This section addresses plans that are the responsibility of BOEM.


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§ 250.204 How must I protect the

rights of the Federal Government? Retained by BSEE ......................... This section describes the responsibilities of the operator to protect the rights of the Federal Government while conducting operationson their lease or units. BSEE will be responsible for offshore operations and ensuring operators fulfill these obligations.§ 250.205 Are there special requirements if my well affects an adjacent property? Retained by BSEE ......................... 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. § 250.206 How do I submit the

EP, DPP, or DOCD? Moved to BOEM, § 550.206 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.207 What ancillary activities

may I conduct? Moved to BOEM, § 550.207 .......... This section is under the responsibility of BOEM.

§ 250.208 If I conduct ancillary activities, what notices must I provide? Moved to BOEM, § 550.208 .......... This section is under the responsibility of BOEM.

§ 250.209 What is the MMS review process for the notice? Moved to BOEM, § 550.209 .......... This section is under the responsibility of BOEM.

§ 250.210 If I conduct ancillary activities, what reporting and data/information retention requirements must I satisfy? Moved to BOEM, § 550.210 .......... This section is under the responsibility of BOEM.

§ 250.211 What must the EP include? Moved to BOEM, § 550.211 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.212 What information must

accompany the EP? Moved to BOEM, § 550.212 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.213 What general information must accompany the EP? Moved to BOEM, § 550.213 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.214 What geological and

geophysical (G&G) information must accompany the EP? Moved to BOEM, § 550.214 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.215 What hydrogen sulfide

(H 2S) information must accompany the EP? Moved to BOEM, § 550.215 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.216 What biological, physical, and socioeconomic information must accompany the EP? Moved to BOEM, § 550.216 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.217 What solid and liquid

wastes and discharges information and cooling water intake information must accompany the

EP? Moved to BOEM, § 550.217 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.218 What air emissions information must accompany the

EP? Moved to BOEM, § 550.218 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.219 What oil and hazardous

substance spills information must accompany the EP? Moved to BOEM, § 550.219 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.220 If I propose activities in

the Alaska OCS Region, whatplanning information must accompany the EP? Moved to BOEM, § 550.220 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.221 What environmental

monitoring information must accompany the EP? Moved to BOEM, § 550.221 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.222 What lease stipulations

information must accompany the

EP? Moved to BOEM, § 550.222 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.223 What mitigation measures information must accompany the EP? Moved to BOEM, § 550.223 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.224 What information on

support vessels, offshore vehicles, and aircraft you will use must accompany the EP? Moved to BOEM, § 550.224 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.225 What information on the

onshore support facilities you will use must accompany the EP? Moved to BOEM, § 550.225 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.226 What Coastal Zone

Management Act (CZMA) information must accompany the EP? Moved to BOEM, § 550.226 .......... This section addresses plans that are the responsibility of BOEM.


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§ 250.227 What environmental impact analysis (EIA) information must accompany the EP? Moved to BOEM, § 550.227 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.228 What administrative information must accompany the

EP? Moved to BOEM, § 550.228 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.231 After receiving the EP,

what will MMS do? Moved to BOEM, § 550.231 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.232 What actions will MMS

take after the EP is deemed submitted? Moved to BOEM, § 550.232 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.233 What decisions will

MMS make on the EP and within

what timeframe? Moved to BOEM, § 550.233 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.234 How do I submit a

modified EP or resubmit a disapproved EP, and when will
MMS make a decision? Moved to BOEM, § 550.234 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.235 If a State objects to the

EP’s coastal zone consistency certification, what can I do? Moved to BOEM, § 550.235 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.241 What must the DPP or

DOCD include? Moved to BOEM, § 550.241 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.242 What information must

accompany the DPP or DOCD? Moved to BOEM, § 550.242 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.243 What general information must accompany the DPP or
DOCD? Moved to BOEM, § 550.243 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.244 What geological and

geophysical (G&G) information must accompany the DPP or
DOCD? Moved to BOEM, § 550.244 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.245 What hydrogen sulfide

(H 2S) information must accompany the DPP or DOCD? Moved to BOEM, § 550.245 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.246 What mineral resource

conservation information must accompany the DPP or DOCD? Moved to BOEM, § 550.246 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.247 What biological, physical, and socioeconomic information must accompany the DPP or
DOCD? Moved to BOEM, § 550.247 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.248 What solid and liquid

wastes and discharges information and cooling water intake information must accompany the

DPP or DOCD? Moved to BOEM, § 550.248 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.249 What air emissions information must accompany the

DPP or DOCD? Moved to BOEM, § 550.249 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.250 What oil and hazardous

substance spills information must accompany the DPP or DOCD? Moved to BOEM, § 550.250 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.251 If I propose activities in

the Alaska OCS Region, whatplanning information must accompany the DPP? Moved to BOEM, § 550.251 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.252 What environmental

monitoring information must accompany the DPP or DOCD? Moved to BOEM, § 550.252 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.253 What lease stipulations

information must accompany the

DPP or DOCD? Moved to BOEM, § 550.253 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.254 What mitigation measures information must accompany the DPP or DOCD? Moved to BOEM, § 550.254 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.255 What decommissioning

information must accompany the

DPP or DOCD? Moved to BOEM, § 550.255 .......... This section addresses plans that are the responsibility of BOEM.


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§ 250.256 What related facilities

and operations information must accompany the DPP or DOCD? Moved to BOEM, § 550.256 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.257 What information on the

support vessels, offshore vehicles, and aircraft you will use must accompany the DPP or
DOCD? Moved to BOEM, § 550.257 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.258 What information on the

onshore support facilities you will use must accompany the DPP or
DOCD? Moved to BOEM, § 550.258 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.259 What sulphur operations information must accompany the DPP or DOCD? Moved to BOEM, § 550.259 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.260 What Coastal Zone

Management Act (CZMA) information must accompany the DPP
or DOCD? Moved to BOEM, § 550.260 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.261 What environmental impact analysis (EIA) information must accompany the DPP or
DOCD? Moved to BOEM, § 550.261 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.262 What administrative information must accompany the

DPP or DOCD? Moved to BOEM, § 550.262 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.266 After receiving the DPP

or DOCD, what will MMS do? Moved to BOEM, § 550.266 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.267 What actions will MMS

take after the DPP or DOCD is

deemed submitted? Moved to BOEM, § 550.267 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.268 How does MMS respond to recommendations? Moved to BOEM, § 550.268 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.269 How will MMS evaluate

the environmental impacts of the

DPP or DOCD? Moved to BOEM, § 550.269 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.270 What decisions will

MMS make on the DPP or

DOCD and within what timeframe? Moved to BOEM, § 550.270 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.271 For what reasons will

MMS disapprove the DPP or

DOCD? Moved to BOEM, § 550.271 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.272 If a State objects to the

DPP’s or DOCD’s coastal zone consistency certification, what

can I do? Moved to BOEM, § 550.272 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.273 How do I submit a

modified DPP or DOCD or resubmit a disapproved DPP or
DOCD? Moved to BOEM, § 550.273 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.280 How must I conduct activities under the approved EP, DPP, or DOCD? Moved to BOEM, § 550.280 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.281 What must I do to conduct activities under the approved EP, DPP, or DOCD? Moved to BOEM, § 550.281 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.282 Do I have to conduct

post-approval monitoring? Both BSEE and BOEM, § 550.282 Both BOEM and BSEE will have oversight functions for post-approval monitoring. § 250.283 When must I revise or

supplement the approved EP, DPP, or DOCD? Moved to BOEM, § 550.283 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.284 How will MMS require

revisions to the approved EP, DPP, or DOCD? Moved to BOEM, § 550.284 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.285 How do I submit revised and supplemental EPs, DPPs, and DOCDs? Moved to BOEM, § 550.285 .......... This section addresses plans that are the responsibility of BOEM.

§ 250.286 What is a DWOP? Retained by BSEE ......................... This section addresses DWOPs that are part of Field Operations and under the authority of BSEE.


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§ 250.287 For what development

projects must I submit a DWOP? Retained by BSEE ......................... This section addresses DWOPs that are part of Field Operations and under the authority of BSEE. § 250.288 When and how must I

submit the Conceptual Plan? Retained by BSEE ......................... This section addresses DWOPs that are part of Field Operations and under the authority of BSEE.§ 250.289 What must the Conceptual Plan contain? Retained by BSEE ......................... This section addresses DWOPs that are part of Field Operations and under the authority of BSEE. § 250.290 What operations require

approval of the Conceptual Plan? Retained by BSEE ......................... This section addresses DWOPs that are part of Field Operations and under the authority of BSEE. § 250.291 When and how must I

submit the DWOP? Retained by BSEE ......................... This section addresses DWOPs that are part of Field Operations and under the authority of BSEE. § 250.292 What must the DWOP

contain? Retained by BSEE ......................... This section addresses DWOPs that are part of Field Operations and under the authority of BSEE. § 250.293 What operations require

approval of the DWOP? Retained by BSEE ......................... This section addresses DWOPs that are part of Field Operations and under the authority of BSEE. § 250.294 May I combine the

Conceptual Plan and the DWOP? Retained by BSEE ......................... This section addresses DWOPs that are part of Field Operations and under the authority of BSEE. § 250.295 When must I revise my

DWOP? Retained by BSEE ......................... This section addresses DWOPs that are part of Field Operations and under the authority of BSEE. § 250.296 When and how must I

submit a CID or a revision to a

CID? Moved to BOEM, § 550.296 .......... This section addresses Conservation Information Documents (CIDs) that are under the authority of BOEM to manage development ofthe Nation’s offshore resources in an environmentally and economically responsible way. § 250.297 What information must

a CID contain? Moved to BOEM, § 550.297 .......... This section addresses CIDs that are under the authority of BOEM tomanage development of the Nation’s offshore resources in an environmentally and economically responsible way. § 250.298 How long will MMS

take to evaluate and make a decision on the CID? Moved to BOEM, § 550.298 .......... This section addresses CIDs that are under the authority of BOEM tomanage development of the Nation’s offshore resources in an environmentally and economically responsible way. § 250.299 What operations require

approval of the CID? Moved to BOEM, § 550.299 .......... This section addresses CIDs that are under the authority of BOEM tomanage development of the Nation’s offshore resources in an environmentally and economically responsible way.

**Subpart C—Pollution Prevention and Control**

§ 250.300 Pollution prevention ..... Retained by BSEE ......................... This section addresses pollution prevention during offshore operations. Offshore operations are under the authority of BSEE. § 250.301 Inspection of facilities ... Retained by BSEE ......................... BSEE will be responsible for all inspection activities on the OCS. § 250.302 Definitions concerning

air quality. Moved to BOEM, § 550.302 .......... This section pertains to air quality concerns that are under the authority of BOEM. § 250.303 Facilities described in a

new or revised Exploration Plan or Development and Production

Plan. Moved to BOEM, § 550.303 .......... This section pertains to air quality concerns that are under the authority of BOEM.

§ 250.304 Existing facilities ........... Moved to BOEM, § 550.304 .......... 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.

**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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**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 ......................... This section addresses pipelines and pipeline rights-of-way on the OCS, which are offshore operations. Offshore operations are under the authority of BSEE. § 250.1001 Definitions .................. Retained by BSEE ......................... This section addresses pipelines and pipeline rights-of-way on the OCS, which are offshore operations. Offshore operations are under the authority of BSEE. § 250.1002 Design requirements

for DOI pipelines. 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. § 250.1003 Installation, testing,

and repair requirements for DOI pipelines. 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.§ 250.1004 Safety equipment requirements for DOI pipelines. 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.§ 250.1005 Inspection requirements for DOI pipelines. 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.§ 250.1006 How must I decommission and take out of service a DOI pipeline? 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.§ 250.1007 What to include in applications. 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. § 250.1008 Reports ....................... Retained by BSEE ......................... This section addresses pipelines and pipeline rights-of-way on the OCS, which are offshore operations. Offshore operations are under the authority of BSEE.§ 250.1009 Requirements to obtain pipeline right-of-way grants. Retained by 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. § 250.1010 General requirements

for pipeline right-of-way holders. Retained by 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. § 250.1011 Bond requirements for

pipeline right-of-way holders. Moved to BOEM, § 550.1011 ........ All bonding is under the authority of BOEM.

§ 250.1012 Required payments for

pipeline right-of-way holders. Retained by 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. § 250.1013 Grounds for forfeiture

of pipeline right-of-way grants. Retained by 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.§ 250.1014 When pipeline right-ofway grants expire. Retained by 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.§ 250.1015 Applications for pipeline right-of-way grants. Retained by 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. § 250.1016 Granting pipeline

rights-of-way. Retained by 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.§ 250.1017 Requirements for construction under pipeline right-ofway grants. Retained by 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. § 250.1018 Assignment of pipeline

right-of-way grants. Retained by 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. § 250.1019 Relinquishment of

pipeline right-of-way grants. Retained by 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.

**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 responsibilit ies.


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§ 250.1150 What are the general

reservoir production requirements? Retained by BSEE ......................... This section addresses oil and gas production requirements that are part of offshore operations and are under the authority of BSEE.

§ 250.1151 How often must I conduct well production tests? Retained by BSEE ......................... This section addresses oil and gas production requirements that are part of offshore operations and are under the authority of BSEE. § 250.1152 How do I conduct well

tests? Retained by BSEE ......................... This section addresses oil and gas production requirements that are part of offshore operations and are under the authority of BSEE. § 250.1153 When must I conduct

a static bottomhole pressure survey? Moved to BOEM, § 550.1153 ........ BOEM will oversee these requirements because they are operator reporting requirements that can be separated from BSEE’s enforcement responsibilities. § 250.1154 How do I determine if

my reservoir is sensitive? Moved to BOEM, § 550.1154 ........ BOEM will oversee these requirements because they are operator reporting requirements that can be separated from BSEE’s enforcement responsibilities. § 250.1155 What information must

I submit for sensitive reservoirs? Moved to BOEM, § 550.1155 ........ BOEM will oversee these requirements because they are operator reporting requirements that can be separated from BSEE’s enforcement responsibilities. § 250.1156 What steps must I

take to receive approval to produce within 500 feet of a unit

or lease line? Retained by BSEE ......................... This section addresses oil and gas production requirements that are part of offshore operations and are under the authority of BSEE.

§ 250.1157 How do I receive approval to produce gas-cap gas

from an oil reservoir with an associated gas cap? Retained by BSEE ......................... This section addresses oil and gas production requirements that are part of offshore operations and are under the authority of BSEE.

§ 250.1158 How do I receive approval to downhole commingle hydrocarbons? Retained by BSEE ......................... This section addresses oil and gas production requirements that are part of offshore operations and are under the authority of BSEE.

§ 250.1159 May the Regional Supervisor limit my well or reservoir production rates? Retained by BSEE ......................... This section addresses oil and gas production requirements that are part of offshore operations and are under the authority of BSEE.

§ 250.1160 When may I flare or

vent gas? Retained by BSEE ......................... This section addresses oil and gas production requirements that are part of offshore operations and are under the authority of BSEE. § 250.1161 When may I flare or

vent gas for extended periods of

time? Retained by BSEE ......................... This section addresses oil and gas production requirements that are part of offshore operations and are under the authority of BSEE.

§ 250.1162 When may I burn produced liquid hydrocarbons? Retained by BSEE ......................... This section addresses oil and gas production requirements that are part of offshore operations and are under the authority of BSEE. § 250.1163 How must I measure

gas flaring or venting volumes and liquid hydrocarbon burning volumes, and what records must

I maintain? Retained by BSEE ......................... This section addresses oil and gas production requirements that are part of offshore operations and are under the authority of BSEE.

§ 250.1164 What are the requirements for flaring or venting gas containing H 2S? Retained by BSEE ......................... This section addresses oil and gas production requirements that are part of offshore operations and are under the authority of BSEE.

§ 250.1165 What must I do for enhanced recovery operations? Responsibilities divided between BSEE and BOEM, § 550.1165(b). This section addresses oil and gas production requirements that are part of offshore operations and are under the authority of BSEE. Paragraph 550.1165 (b) refers operators to BSEE for approval.§ 250.1166 What additional reporting is required for developments in the Alaska OCS Region? Responsibilities divided between BSEE and BOEM, § 550.1166(c). BSEE will oversee these requirements because they are operator reporting 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. § 250.1167 What information must

I submit with forms and for approvals? Responsibilities divided between
BSEE and BOEM. This section addresses information to be submitted; both BSEE and

BOEM functions.

**Subpart L—Oil and Gas Production Measurement, Surface Commingling, and Security**

Retained in its entirety by BSEE. This subpart addresses production measurement, which is a responsibility of BSEE, under its authority for regulatory enforcement of conservation compliance.

**Subpart M—Unitization**

Retained in its entirety by BSEE. This subpart addresses unitization, which is a responsibility of BSEE, under its authority for regulatory enforcement of conservation compliance.


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**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 safetyand 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 reso urces.

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.



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

§ 251.1 Definitions ........................ Both BSEE and BOEM, § 551.1 .... Definitions section, the same definitions apply to both bureaus. § 251.2 Purpose of this part ......... Moved to BOEM, § 551.2 .............. This section addresses prelease G&G activities. Prelease activities are under the authority of BOEM. § 251.3 Authority and applicability

of this part. Both BSEE and BOEM, § 551.3 .... This section addresses prelease G&G activities. Prelease activities are under the authority of BOEM. § 251.4 Types of G&G activities

that require permits or Notices. Moved to BOEM, § 551.4 .............. This section addresses prelease G&G activities. Prelease activities are under the authority of BOEM.§ 251.5 Applying for permits or filing Notices. Moved to BOEM, § 551.5 .............. This section addresses prelease G&G activities. Prelease activities are under the authority of BOEM. § 251.6 Obligations and rights

under a permit or a Notice. Moved to BOEM, § 551.6 .............. This section addresses prelease G&G activities. Prelease activities are under the authority of BOEM. § 251.7 Test drilling activities

under a permit. Responsibilities divided between
both BSEE and 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. § 251.8 Inspection and reporting

requirements for activities under a permit. Moved to BOEM, § 551.8 .............. This section addresses prelease G&G activities. Prelease activities are under the authority of BOEM.

§ 251.9 Temporarily stopping,

canceling, or relinquishing activities approved under a permit. Moved to BOEM, § 551.9 .............. This section addresses prelease G&G activities. Prelease activities are under the authority of BOEM.

§ 251.10 Penalties and appeals ... Moved to BOEM, § 551.10 ............ This section addresses prelease G&G activities. Prelease activ ities are under the authority of BOEM. § 251.11 Submission, inspection,

and selection of geological data

and information collected under apermit and processed by permittees or third parties. Moved to BOEM, § 551.11 ............ This section addresses prelease G&G activities. Prelease activities are under the authority of BOEM.


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§ 251.12 Submission, inspection,

and selection of geophysical data

and information collected under apermit and processed by permittees or third parties. Moved to BOEM, § 551.12 ............ This section addresses prelease G&G activities. Prelease activities are under the authority of BOEM.

§ 251.13 Reimbursement for the

costs of reproducing data and information and certain processing

costs. Moved to BOEM, § 551.13 ............ This section addresses prelease G&G activities. Prelease activities are under the authority of BOEM.

§ 251.14 Protecting and disclosing

data and information submitted to MMS under a permit. Moved to BOEM, § 551.14 ............ This section addresses prelease G&G activities. Prelease activities are under the authority of BOEM.

§ 251.15 Authority for information

collection. In both BSEE and BOEM § 551.15 This section establishes the authority for the bureaus to collect therequired 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.



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

§ 252.1 Purpose ............................ In both BSEE and BOEM § 552.1 Both BSEE and BOEM will collect, maintain, and use data co llected under this program. Both bureaus are responsible for managing the data and determining how and when the data is released.§ 252.2 Definitions ........................ In both BSEE and BOEM § 552.2 Definitions section. The same definitions apply to both sets of regulations.§ 252.3 Oil and gas data and information to be provided for use

in the OCS Oil and Gas Information Program. In both BSEE and BOEM § 552.3 Both BSEE and BOEM will collect.

§ 252.4 Summary Report to affected States. In both BSEE and BOEM § 552.4 Both BSEE and BOEM will collect.

§ 252.5 Information to be made

available to affected States. In both BSEE and BOEM § 552.5 Both BSEE and BOEM will collect.

§ 252.6 Freedom of Information

Act requirements. In both BSEE and BOEM § 552.6 Both BSEE and BOEM will collect.

§ 252.7 Privileged and proprietary

data and information to be made

available to affected States. 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

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


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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 .............. 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. § 253.3 How are the terms used

in this regulation defined? Moved to BOEM, § 553.3 .............. BOEM is responsible for all activities related to financial assurance.

§ 253.5 What is the authority for

collecting Oil Spill Financial Responsibility (OSFR) information? 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? Moved to BOEM, § 553.10 ............ BOEM is responsible for all activities related to financial assurance.

§ 253.11 Who must demonstrate

OSFR? Moved to BOEM, § 553.11 ............ BOEM is responsible for all activities related to financial assurance.

§ 253.12 May I ask MMS for a determination of whether I must

demonstrate OSFR? Moved to BOEM, § 553.12 ............ BOEM is responsible for all activities related to financial assurance.

§ 253.13 How much OSFR must I

demonstrate? Moved to BOEM, § 553.13 ............ BOEM is responsible for all activities related to financial assurance.

§ 253.14 How do I determine the

worst case oil-spill discharge volume? Moved to BOEM, § 553.14 ............ BOEM is responsible for all activities related to financial assurance.

§ 253.15 What are my general

OSFR compliance responsibilities? Moved to BOEM, § 553.15 ............ BOEM is responsible for all activities related to financial assurance.

**Subpart C—Methods for Demonstrating OSFR**

§ 253.20 What methods may I use

to demonstrate OSFR? Moved to BOEM, § 553.20 ............ BOEM is responsible for all activities related to financial assurance.

§ 253.21 How can I use self-insurance as OSFR evidence? Moved to BOEM, § 553.21 ............ BOEM is responsible for all activities related to financial assurance.

§ 253.22 How do I apply to use

self-insurance as OSFR evidence? Moved to BOEM, § 553.22 ............ BOEM is responsible for all activities related to financial assurance.

§ 253.23 What information must I

submit to support my net worth

demonstration? Moved to BOEM, § 553.23 ............ BOEM is responsible for all activities related to financial assurance.

§ 253.24 When I submit audited

annual financial statements toverify my net worth, what standards must they meet? Moved to BOEM, § 553.24 ............ BOEM is responsible for all activities related to financial assurance.

§ 253.25 What financial test procedures must I use to determine

the amount of self-insurance allowed as OSFR evidence based

on net worth? Moved to BOEM, § 553.25 ............ BOEM is responsible for all activities related to financial assurance.

§ 253.26 What information must I

submit to support my

unencumbered assets demonstration? Moved to BOEM, § 553.26 ............ BOEM is responsible for all activities related to financial assurance.

§ 253.27 When I submit audited

annual financial statements to verify my unencumbered assets, what standards must they meet? Moved to BOEM, § 553.27 ............ BOEM is responsible for all activities related to financial assurance.

§ 253.28 What financial test procedures must I use to evaluate

the amount of self-insurance allowed as OSFR evidence based

on unencumbered assets? Moved to BOEM, § 553.28 ............ BOEM is responsible for all activities related to financial assurance.

§ 253.29 How can I use insurance

as OSFR evidence? Moved to BOEM, § 553.29 ............ BOEM is responsible for all activities related to financial assurance.

§ 253.30 How can I use an indemnity as OSFR evidence? Moved to BOEM, § 553.30 ............ BOEM is responsible for all activities related to financial assurance.

§ 253.31 How can I use a surety

bond as OSFR evidence? Moved to BOEM, § 553.31 ............ BOEM is responsible for all activities related to financial assurance.


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§ 253.32 Are there alternative

methods to demonstrate OSFR? Moved to BOEM, § 553.32 ............ 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? Moved to BOEM, § 553.40 ............ BOEM is responsible for all activities related to financial assurance.

§ 253.41 What terms must I include in my OSFR evidence? Moved to BOEM, § 553.41 ............ BOEM is responsible for all activities related to financial assurance.

§ 253.42 How can I amend my list

of COFs? Moved to BOEM, § 553.42 ............ BOEM is responsible for all activities related to financial assurance.

§ 253.43 When is my OSFR demonstration or the amendment tomy OSFR demonstration effective? Moved to BOEM, § 553.43 ............ BOEM is responsible for all activities related to financial assurance.

§ 253.44 [Reserved] ...................... § 553.44 [Reserved] .................... BOEM is responsible for all activities related to financial assurance. § 253.45 Where do I send my

OSFR evidence? Moved to BOEM, § 553.45 ............ 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? Moved to BOEM, § 553.50 ............ BOEM is responsible for all activities related to financial assurance.

§ 253.51 What are the penalties

for not complying with this part? 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? Moved to BOEM, § 553.60 ............ BOEM is responsible for all activities related to financial assurance.

§ 253.61 When is a guarantor

subject to direct action for

claims? Moved to BOEM, § 553.61 ............ BOEM is responsible for all activities related to financial assurance.

§ 253.62 What are the designated

applicant’s notification obligations regarding a claim? Moved to BOEM, § 553.62 ............ BOEM is responsible for all activities related to financial assurance.

Appendix—Appendix to Part 253—

List of U.S. Geological Survey Topographic Maps. 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

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



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**Subpart A—General**

§ 254.1 Who must submit a spillresponse plan? 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.§ 254.2 When must I submit a response plan? 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. § 254.3 May I cover more than

one facility in my response plan? 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. § 254.4 May I reference other

documents in my response plan? 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.§ 254.5 General response plan requirements. 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. § 254.6 Definitions ........................ 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.§ 254.7 How do I submit my response plan to the MMS? 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.


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§ 254.8 May I appeal decisions

under this part? 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. § 254.9 Authority for information

collection. 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 B—Oil-Spill Response Plans for Outer Continental Shelf Facilities**

§ 254.20 Purpose .......................... 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. § 254.21 How must I format my

response plan? 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. § 254.22 What information must I

include in the ‘‘Introduction and plan contents’’ section? 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.

§ 254.23 What information must I

include in the ‘‘Emergency response action plan’’ section? 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.

§ 254.24 What information must I

include in the ‘‘Equipment inventory’’ appendix? 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.

§ 254.25 What information must I

include in the ‘‘Contractual agreements’’ appendix? 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.

§ 254.26 What information must I

include in the ‘‘Worst case discharge scenario’’ appendix? 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.

§ 254.27 What information must I

include in the ‘‘Dispersant use plan’’ appendix? 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.

§ 254.28 What information must I

include in the ‘‘In situ burning plan’’ appendix? 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.

§ 254.29 What information must I

include in the ‘‘Training and drills’’ appendix? 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.

§ 254.30 When must I revise my

response plan? 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**

§ 254.40 Records .......................... 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. § 254.41 Training your response

personnel. 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.§ 254.42 Exercises for your response personnel and equipment. 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.§ 254.43 Maintenance and periodic inspection of response equipment. 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.

§ 254.44 Calculating response

equipment effective daily recovery capacities. 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.

§ 254.45 Verifying the capabilities

of your response equipment. 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. § 254.46 Whom do I notify if an oil

spill occurs? 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. § 254.47 Determining the volume

of oil of your worst case discharge scenario. 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 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. 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.

§ 254.51 Modifying an existing

OCS response plan. 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. § 254.52 Following the format for

an OCS response plan. 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.


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§ 254.53 Submitting a response

plan developed under State requirements. 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.

§ 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.

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.



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

§ 256.0 Authority for information

collection. Moved to BOEM, § 556.0 .............. This section addresses leasing activities on the OCS that are under the authority of BOEM. § 256.1 Purpose ............................ Moved to BOEM, § 556.1, retained purpose except for right-of-waygrant clause; under BSEE retained right-of-way grant clause. This section addresses leasing activities on the OCS that are under the authority of BOEM.

§ 256.2 Policy ................................ Moved to BOEM, § 556.2 .............. This section addresses leasing activities on the OCS that are under the authority of BOEM. § 256.4 Authority ........................... Moved to BOEM, § 556.4 .............. This section addresses leasing activities on the OCS that are under the authority of BOEM. § 256.5 Definitions ........................ Moved to BOEM, § 556.5 .............. This section addresses leasing activities on the OCS that are under the authority of BOEM. § 256.7 Cross references .............. Both BSEE and BOEM § 556.7 ..... This section contains cross references that are pertinent to both
BSEE and BOEM activities.§ 256.8 Leasing maps and diagrams. Moved to BOEM, § 556.8 .............. This section addresses leasing activities on the OCS that are under the authority of BOEM. § 256.10 Information to States ...... Moved to BOEM, § 556.10 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM. § 256.11 Helium ............................ Moved to BOEM, § 556.11 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM. § 256.12 Supplemental sales ........ Moved to BOEM, § 556.12 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM.

**Subpart B—Oil and Gas Leasing Program**

§ 256.16 Receipt and consideration of nominations; public notice and participation. Moved to BOEM, § 556.16 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM.

§ 256.17 Review by State and

local governments and other persons. Moved to BOEM, § 556.17 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM.

§ 256.19 Periodic consultation

with interested parties. Moved to BOEM, § 556.19 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM. § 256.20 Consideration of coastal

zone management program. Moved to BOEM, § 556.20 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM.

**Subpart C—Reports From Federal Agencies**

§ 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 ...... Moved to BOEM, § 556.23 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM. § 256.25 Areas near coastal

states. Moved to BOEM, § 556.25 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM.


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**Subpart E—Area Identification and Tract Size**

§ 256.26 General .......................... Moved to BOEM, § 556.26 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM. § 256.28 Tract size ....................... Moved to BOEM, § 556.28 ............ 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 ............ This section addresses leasing activities on the OCS that are u nder the authority of BOEM. § 256.31 State comments ............. Moved to BOEM, § 556.31 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM. § 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.

**Subpart G—Issuance of Leases**

§ 256.35 Qualifications of lessees Moved to BOEM, § 556.35 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM. § 256.37 Lease term ..................... Moved to BOEM, § 556.37 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM. § 256.38 Joint bidding provisions Moved to BOEM, § 556.38 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM. § 256.40 Definitions ...................... Moved to BOEM, § 556.40 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM.§ 256.41 Joint bidding requirements. Moved to BOEM, § 556.41 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM.§ 256.43 Chargeability for production. Moved to BOEM, § 556.43 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM. § 256.44 Bids disqualified ............. Moved to BOEM, § 556.44 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM. § 256.46 Submission of bids ......... Moved to BOEM, § 556.46 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM. § 256.47 Award of leases ............. Moved to BOEM, § 556.47 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM. § 256.49 Lease form ..................... Moved to BOEM, § 556.49 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM. § 256.50 Dating of leases ............. Moved to BOEM, § 556.50 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM.

**Subpart H—Rentals and Royalties [Reserved]**

**Subpart I—Bonding**

§ 256.52 Bond requirements for

an oil and gas or sulphur lease. Moved to BOEM, § 556.52 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM. § 256.53 Additional bonds ............ Moved to BOEM, § 556.53 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM. § 256.54 General requirements for

bonds. Moved to BOEM, § 556.54 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM. § 256.55 Lapse of bond ................ Moved to BOEM, § 556.55 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM.§ 256.56 Lease-specific abandonment accounts. Moved to BOEM, § 556.56 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM.§ 256.57 Using a third-party guarantee instead of a bond. Moved to BOEM, § 556.57 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM. § 256.58 Termination of the period

of liability and cancellation of a

bond. Moved to BOEM, § 556.58 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM.

§ 256.59 Forfeiture of bonds and/

or other securities. Moved to BOEM, § 556.59 ............ 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. Moved to BOEM, § 556.62 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM. § 256.63 Service fees ................... Moved to BOEM, § 556.63 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM. § 256.64 How to file transfers ....... Moved to BOEM, § 556.64 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM.


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Current citation and BSEE citation (if applicable) Implementing bureau and BOEM citation (if applicable) Explanation

§ 256.65 Attorney General review Moved to BOEM, § 556.65 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM.§ 256.67 Separate filings for assignments. Moved to BOEM, § 556.67 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM. § 256.68 Effect of assignment of a

particular tract. Moved to BOEM, § 556.68 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM. § 256.70 Extension of lease by

drilling or well reworking operations. Both BSEE and BOEM § 556.70 ... Needed by both agencies.

§ 256.71 Directional drilling ........... Both BSEE and BOEM § 556.71 ... Needed by both agencies. § 256.72 Compensatory payments

as production. Both BSEE and BOEM § 556.72 ... Needed by both agencies.

§ 256.73 Effect of suspensions on

lease term. Retained by BSEE ......................... This section addresses enforcement of suspension activities on the OCS that is under the authority of BSEE. Beyond the primary leaseterm, BSEE’s oversight over operations and production and suspensions thereof determine the lease term.

**Subpart K—Termination of Leases**

§ 256.76 Relinquishment of leases

or parts of leases. Moved to BOEM, § 556.76 ............ This section addresses leasing administration on the OCS that are under the authority of BOEM. § 256.77 Cancellation of leases .... Both BSEE and BOEM, § 556.77 .. BOEM is authorized to cancel leases. BSEE has the authority to in itiate lease cancellation.

**Subpart L—Section 6 Leases**

§ 256.79 Effect of regulations on

lease. Both BSEE and BOEM § 556.79 ... Needed by both agencies.

§ 256.80 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**

§ 256.90 Which leases may I exchange for a bonus or royalty

credit? Moved to BOEM, § 556.90 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM.

§ 256.91 How much bonus or royalty credit will MMS grant in exchange for a lease? Moved to BOEM, § 556.91 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM.

§ 256.92 What must I do to obtain

a bonus or royalty credit? Moved to BOEM, § 556.92 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM.§ 256.93 How is the bonus or royalty credit allocated among multiple lease owners? Moved to BOEM, § 556.93 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM.

§ 256.94 How may I use the

bonus or royalty credit? Moved to BOEM, § 556.94 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM. § 256.95 How do I transfer a

bonus or royalty credit to another person? Moved to BOEM, § 556.95 ............ This section addresses leasing activities on the OCS that are under the authority of BOEM.

APPENDIX A PART 256—Appendix A to Part 256—Oil and Gas

Cash Bonus Bid. 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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Current citation and BSEE citation (if applicable) Implementing bureau and BOEM citation (if applicable) Explanation

§ 259.001 Purpose and scope ...... Moved to BOEM, § 559.001 .......... This section addresses definitions used in lease administration under the authority of BOEM. § 259.002 Definitions .................... Moved to BOEM, § 559.002 .......... This section used in lease administration under the authority of

BOEM.

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

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

thresholds.



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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? Moved to BOEM, § 560.1 .............. This section addresses leasing activities on the OCS that are under the authority of BOEM. § 260.2 What definitions apply to

this part? Moved to BOEM, § 560.2 .............. This section addresses leasing activities on the OCS that are under the authority of BOEM. § 260.3 What is MMS’s authority

to collect information? Moved to BOEM, § 560.3 .............. This section addresses leasing activities on the OCS that are under the authority of BOEM.

**Subpart B—Bidding Systems**

§ 260.101 What is the purpose of

this subpart? Moved to BOEM, § 560.101 .......... This section addresses leasing activities on the OCS that are under the authority of BOEM. § 260.102 What definitions apply

to this subpart? Moved to BOEM, § 560.102 .......... This section addresses leasing activities on the OCS that are under the authority of BOEM. § 260.110 What bidding systems

may MMS use? Moved to BOEM, § 560.110 .......... This section addresses leasing activities on the OCS that are under the authority of BOEM. § 260.111 What conditions apply

to the bidding systems that MMS

uses? Moved to BOEM, § 560.111 .......... This section addresses leasing activities on the OCS that are under the authority of BOEM.

§ 260.112 How do royalty suspension volumes apply to eligible

leases? Moved to BOEM, § 560.112 .......... This section addresses leasing activities on the OCS that are under the authority of BOEM.

§ 260.113 When does an eligible

lease qualify for a royalty suspension volume? Moved to BOEM, § 560.113 .......... This section addresses leasing activities on the OCS that are under the authority of BOEM.

§ 260.114 How does MMS assign

and monitor royalty suspension volumes for eligible leases? Moved to BOEM, § 560.114 .......... This section addresses leasing activities on the OCS that are under the authority of BOEM.

§ 260.115 How long will a royalty

suspension volume for an eligible

lease be effective? Moved to BOEM, § 560.115 .......... This section addresses leasing activities on the OCS that are under the authority of BOEM.

§ 260.116 How do I measure natural gas production on my eligible lease? Moved to BOEM, § 560.116 .......... This section addresses leasing activities on the OCS that are under the authority of BOEM.

§ 260.120 How does royalty suspension apply to leases issued in

a sale held after November

2000? Moved to BOEM, § 560.120 .......... This section addresses leasing activities on the OCS that are under the authority of BOEM.

§ 260.121 When does a lease

issued in a sale held after November 2000 get a royalty suspension? Moved to BOEM, § 560.121 .......... This section addresses leasing activities on the OCS that are under the authority of BOEM.

§ 260.122 How long will a royalty

suspension volume be effective

for a lease issued in a sale held

after November 2000? Moved to BOEM, § 560.122 .......... This section addresses leasing activities on the OCS that are under the authority of BOEM.

§ 260.123 How do I measure natural gas production for a lease

issued in a sale held after November 2000? Moved to BOEM, § 560.123 .......... This section addresses leasing activities on the OCS that are under the authority of BOEM.


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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? Moved to BOEM, § 560.124 .......... This section addresses leasing activities on the OCS that are under the authority of BOEM.

§ 260.130 What criteria does

MMS use for selecting bidding systems and bidding system components? 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? Moved to BOEM, § 560.301 .......... This section addresses leasing activities on the OCS that are under the authority of BOEM. § 260.302 What definitions apply

to this subpart? Moved to BOEM, § 560.302 .......... This section addresses leasing activities on the OCS that are under the authority of BOEM.§ 260.303 What are the joint bidding requirements? Moved to BOEM, § 560.303 .......... 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.



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§ 270.1 Purpose ............................ Revised in both BSEE and BOEM § 570.1. This section addresses the nondiscrimination on the OCS provisions that are relevant to the activities regulated by both BSEE and

BOEM. § 270.2 Application of this part ..... Revised in both BSEE and BOEM § 570.2. This section addresses the nondiscrimination on the OCS provisions that are under the authority of both BSEE and BOEM. § 270.3 Definitions ........................ Revised in both BSEE and BOEM § 570.3. This section addresses the nondiscrimination on the OCS provisions that are under the authority of both BSEE and BOEM. § 270.4 Discrimination prohibited .. Revised in both BSEE and BOEM § 570.4. This section addresses the nondiscrimination on the OCS provisions that are under the authority of both BSEE and BOEM. § 270.5 Complaint ......................... Revised in both BSEE and BOEM § 570.5. This section addresses the nondiscrimination on the OCS provisions that are under the authority of both BSEE and BOEM. § 270.6 Process ............................ Revised in both BSEE and BOEM § 570.6. This section addresses the nondiscrimination on the OCS provisions that are under the authority of both BSEE and BOEM. § 270.7 Remedies ......................... Revised in both BSEE and BOEM § 570.7. This section addresses the nondiscrimination on the OCS provisions that are under the authority of both BSEE and BOEM.

Part 280—Prospecting for Minerals Other Than Oil, Gas, and Sulphur on the Outer Continental Shelf—Moved to BOEM in Its Entirety, Chapter V, Part

580

BOEM is responsible for regulating prospecting activities or scientific research activities on the OCS related to

hard minerals on unleased lands or on lands under lease to a third party.



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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? Moved to BOEM, § 580.1 .............. This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM. § 280.2 What is the purpose of

this part? Moved to BOEM, § 580.2 .............. This section addresses activities within the scope of oil, gas and sulphur prospecting on the OCS under BOEM.


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Current citation and BSEE citation (if applicable) Implementing bureau and BOEM citation (if applicable) Explanation

§ 280.3 What requirements must I

follow when I conductprospecting or research activities? Moved to BOEM, § 580.3 .............. This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.

§ 280.4 What activities are not

covered by this part? 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? Moved to BOEM, § 580.10 ............ This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.

§ 280.11 What must I do before I

may conduct scientific research? Moved to BOEM, § 580.11 ............ This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM. § 280.12 What must I include in

my application or notification? Moved to BOEM, § 580.12 ............ This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM. § 280.13 Where must I send my

application or notification? Moved to BOEM, § 580.13 ............ This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.

**Subpart C—Obligations Under This Part**

§ 280.20 What must I not do in

conducting Geological and Geophysical (G&G) prospecting or

scientific research? Moved to BOEM, § 580.20 ............ This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.

§ 280.21 What must I do in conducting G&G prospecting or scientific research? Moved to BOEM, § 580.21 ............ This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.

§ 280.22 What must I do when

seeking approval for modifications? Moved to BOEM, § 580.22 ............ This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.

§ 280.23 How must I cooperate

with inspection activities? Moved to BOEM, § 580.23 ............ This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.§ 280.24 What reports must I file? Moved to BOEM, § 580.24 ............ This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM. § 280.25 When may MMS require

me to stop activities under this part? Moved to BOEM, § 580.25 ............ This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.

§ 280.26 When may I resume activities? Moved to BOEM, § 580.26 ............ This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM. § 280.27 When may MMS cancel

my permit? In both BSEE and BOEM, § 580.27. This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.§ 280.28 May I relinquish my permit? In both BSEE and BOEM, § 580.28. This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM. § 280.29 Will MMS monitor the

environmental effects of my activity? Moved to BOEM, § 580.29 ............ This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.

§ 280.30 What activities will not

require environmental analysis? Moved to BOEM, § 580.30 ............ This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM. § 280.31 Whom will MMS notify

about environmental issues? Moved to BOEM, § 580.31 ............ This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM. § 280.32 What penalties may I be

subject to? Moved to BOEM, § 580.32 ............ This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.§ 280.33 How can I appeal a penalty? Moved to BOEM, § 580.33 ............ This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM. § 280.34 How can I appeal an

order or decision? Moved to BOEM, § 580.34 ............ This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.

**Subpart D—Data Requirements**

§ 280.40 When do I notify MMS

that geological data and information are available for submission, inspection, and selection? Moved to BOEM, § 580.40 ............ This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.

§ 280.41 What types of geological

data and information must I submit to MMS? Moved to BOEM, § 580.41 ............ This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.

§ 280.42 When geological data

and information are obtained by a third party, what must we both

do? 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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§ 280.50 When do I notify MMS

that geophysical data and information are available for submission, inspection, and selection? Moved to BOEM, § 580.50 ............ This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.

§ 280.51 What types of geophysical data and information

must I submit to MMS? Moved to BOEM, § 580.51 ............ This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.

§ 280.52 When geophysical data

and information are obtained by a third party, what must we both

do? Moved to BOEM, § 580.52 ............ This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.

§ 280.60 Which of my costs will

be reimbursed? Moved to BOEM, § 580.60 ............ This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM. § 280.61 Which of my costs will

not be reimbursed? Moved to BOEM, § 580.61 ............ This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.§ 280.70 What data and information will be protected from public

disclosure? Moved to BOEM, § 580.70 ............ This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.

§ 280.71 What is the timetable for

release of data and information? Moved to BOEM, § 580.71 ............ This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM. § 280.72 What procedure will

MMS follow to disclose acquired

data and information to a contractor for reproduction, processing, and interpretation? Moved to BOEM, § 580.72 ............ This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.

§ 280.73 Will MMS share data

and information with coastal

States? 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 ............ This section addresses activities within the scope of oil, gas and sulphur prospecting on the OCS under BOEM.

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

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



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**Subpart A—General**

§ 281.0 Authority for information

collection. Moved to BOEM, § 581.0 .............. This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.§ 281.1 Purpose and applicability Moved to BOEM, § 581.1 .............. This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.§ 281.2 Authority ........................... Moved to BOEM, § 581.2 .............. This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.§ 281.3 Definitions ........................ Moved to BOEM, § 581.3 .............. This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.§ 281.4 Qualifications of lessees .. Moved to BOEM, § 581.4 .............. This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.§ 281.5 False statements .............. Moved to BOEM, § 581.5 .............. This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.§ 281.6 Appeals ............................ Moved to BOEM, § 581.6 .............. This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM. § 281.7 Disclosure of information

to the public. Moved to BOEM, § 581.7 .............. 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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§ 281.8 Rights to minerals ............ Moved to BOEM, § 581.8 .............. This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.§ 281.9 Jurisdictional controversies. Moved to BOEM, § 581.9 .............. This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.

**Subpart B—Leasing Procedures**

§ 281.11 Unsolicited request for a

lease sale. Moved to BOEM, § 581.11 ............ This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM. § 281.12 Request for OCS mineral

information and interest. Moved to BOEM, § 581.12 ............ This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.§ 281.13 Joint State/Federal coordination. Moved to BOEM, § 581.13 ............ This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.§ 281.14 OCS mining area identification. 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.§ 281.15 Tract size ....................... Moved to BOEM, § 581.15 ............ This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.§ 281.16 Proposed leasing notice Moved to BOEM, § 581.16 ............ This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.§ 281.17 Leasing notice ................ Moved to BOEM, § 581.17 ............ This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.§ 281.18 Bidding system ............... Moved to BOEM, § 581.18 ............ This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.§ 281.19 Lease term ..................... Moved to BOEM, § 581.19 ............ This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.§ 281.20 Submission of bids ......... Moved to BOEM, § 581.20 ............ This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.§ 281.21 Award of leases ............. Moved to BOEM, § 581.21 ............ This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.§ 281.22 Lease form ..................... Moved to BOEM, § 581.22 ............ This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.§ 281.23 Effective date of leases Moved to BOEM, § 581.23 ............ 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 ............ This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.§ 281.27 Annual rental .................. Moved to BOEM, § 581.27 ............ This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.§ 281.28 Royalty ........................... Moved to BOEM, § 581.28 ............ This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.§ 281.29 Royalty valuation ............ Moved to BOEM, § 581 29 .......... This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.§ 281.30 Minimum royalty ............. Moved to BOEM, § 581.30 ............ This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.§ 281.31 Overriding royalties ........ Moved to BOEM, § 581.31 ............ This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM. § 281.32 Waiver, suspension, or

reduction of rental, minimum royalty or production royalty. Moved to BOEM, § 581.32 ............ This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.

§ 281.33 Bonds and bonding requirements. 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.

**Subpart D—Assignments and Lease Extensions**

§ 281.40 Assignment of leases or

interests therein. Moved to BOEM, § 581.40 ............ This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM. § 281.41 Requirements for filing

for transfers. Moved to BOEM, § 581.41 ............ This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM. § 281.42 Effect of assignment on

particular lease. Moved to BOEM, § 581.42 ............ This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM. § 281.43 Effect of suspensions on

lease term. 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.

**Subpart E—Termination of Leases**

§ 281.46 Relinquishment of leases

or parts of leases. Moved to BOEM, § 581.46 ............ This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.§ 281.47 Cancellation of leases .... Moved to BOEM, § 581.47 ............ 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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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:



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**Subpart A—General**

§ 282.0 Authority for information

collection. Both BSEE and BOEM § 582.0 ..... Both agencies need the authority for information collection.

§ 282.1 Purpose and authority ...... Both BSEE and BOEM § 582.1 ..... Needed by both agencies. § 282.2 Scope ............................... Both BSEE and BOEM § 582.2 ..... Needed by both agencies. § 282.3 Definitions ........................ Both BSEE and BOEM § 582.3 ..... Needed by both agencies. § 282.4 Opportunities for review

and comment. Moved to BOEM, § 582.4 .............. BOEM responsibility.

§ 282.5 Disclosure of data and information to the public. Both BSEE and BOEM § 582.5 ..... Needed by both agencies.

§ 282.6 Disclosure of data and information to an adjacent State. Both BSEE and BOEM § 582.6 ..... Needed by both agencies.

§ 282.7 Jurisdictional controversies. Both BSEE and BOEM § 582.7 ..... Needed by both agencies.

**Subpart B—Jurisdiction and Responsibilities of Director**

§ 282.10 Jurisdiction and responsibilities of Director. Both BSEE and BOEM § 582.10 ... Needed by both agencies.

§ 282.11 Director’s authority ......... Moved to BOEM, § 582.11. Paragraph (d) on mining units is in

both. Paragraph (d) involves units, which is a BSEE function. Paragraph (d) also contains BOEM responsibilities as it mentions plans.

§ 282.12 Director’s responsibilities Responsibilities are shared by

both BSEE and BOEM. 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.§ 282.13 Suspension of production or other operations. Retained in BSEE .......................... Suspensions are under the authority of BSEE.

§ 282.14 Noncompliance, remedies, and penalties. Both BSEE and BOEM § 582.14 ... BSEE is responsible for addressing noncompliance, remedies, and penalties. Needed in both agencies. § 282.15 Cancellation of leases .... Moved to BOEM, § 582.15 ............ BOEM is responsible for lease administration.

**Subpart C—Obligations and Responsibilities of Lessees**

§ 282.20 Obligations and responsibilities of lessees. Moved to BOEM, § 582.20 ............ This section addresses obligations and responsibilities of lessees that are the responsibility of BOEM. § 282.21 Plans, general ................ Moved to BOEM, § 582.21, except paragraph (e), which is in both. 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. § 282.22 Delineation Plan ............. Moved to BOEM, § 582.22 ............ This section addresses plans that are the responsibility of BOEM. § 282.23 Testing Plan ................... Moved to BOEM, § 582.23 ............ This section addresses plans that are the responsibility of BOEM. § 282.24 Mining Plan .................... Moved to BOEM, § 582.24 ............ This section addresses plans that are the responsibility of BOEM. § 282.25 Plan modification ............ Moved to BOEM, § 582.25 ............ This section addresses plans that are the responsibility of BOEM. § 282.26 Contingency Plan ........... Moved to BOEM, § 582.26 ............ This section addresses plans that are the responsibility of BOEM. § 282.27 Conduct of operations .... Retained in BSEE. Paragraph (i) also in BOEM, § 582.27. Paragraph (i) addresses plans that are the responsibility of BOEM.

§ 282.28 Environmental protection

measures. 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. 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). § 282.29 Reports and records ...... Moved to BOEM, § 582.29 ............ A resource evaluation function under BOEM.§ 282.30 Right of use and easement. Moved to BOEM, § 582.30 ............ BOEM has the authority to grant rights of use and easement.


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Current citation and BSEE citation (if applicable) Implementing bureau and BOEM citation (if applicable) Explanation

§ 282.31 Suspension of production or other operations. Retained in BSEE .......................... BSEE has the authority to suspend production or other operations.

**Subpart D—Payments**

§ 282.40 Bonds ............................. Moved to BOEM, § 582.40 ............ Financial assurance is a BOEM function with a cross reference provided for BSEE.§ 282.41 Method of royalty calculation. Both BSEE and BOEM, § 582.41 .. ONRR regulations at 30 CFR part 1206 may apply. Otherwise, lessees must comply with BOEM’s procedures specified in lease notices. § 282.42 Payments ....................... Moved to BOEM, § 582.42 ............ BOEM.

**Subpart E—Appeals**

§ 282.50 Appeals .......................... Both BSEE and BOEM, § 582.50 .. Both agencies need the procedures for addressing appeals.

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

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

BSEE and BOEM. Subchapter C—Appeals

Part 290—Appeals Procedures—Both

BSEE and BOEM Will Have This Part in Its Entirety



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**Subpart A—Offshore Minerals Management Appeal Procedures**

§ 290.1 What is the purpose of

this subpart? Both BSEE and BOEM § 590.1 ..... Both BSEE and BOEM need to provide opportunity for appeals of decisions.§ 290.2 Who may appeal? Both BSEE and BOEM § 590.2 ..... Both BSEE and BOEM need to provide opportunity for appeals of decisions. § 290.3 What is the time limit for

filing an appeal? Both BSEE and BOEM § 590.3 ..... Both BSEE and BOEM. need to provide opportunity for appeals of

decisions. § 290.4 How do I file an appeal? Both BSEE and BOEM § 590.4 ..... Both BSEE and BOEM need to provide opportunity for appeals of decisions. § 290.5 Can I obtain an extension

for filing my Notice of Appeal? Both BSEE and BOEM § 590.5 ..... Both BSEE and BOEM need to provide opportunity for appeals of decisions. § 290.6 Are informal resolutions

permitted? Both BSEE and BOEM § 590.6 ..... Both BSEE and BOEM need to provide opportunity for appeals of decisions. § 290.7 Do I have to comply with

the decision or order while my appeal is pending? Both BSEE and BOEM § 590.7 ..... Both BSEE and BOEM need to provide opportunity for appeals of decisions.

§ 290.8 How do I exhaust my administrative remedies? Both BSEE and BOEM § 590.8 ..... 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



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**SUBCHAPTER C—APPEALS**

§ 291.1 What is MMS’s authority

to collect information? Retained in its entirety in BSEE, chapter II. 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.


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§ 291.100 What is the purpose of

this part? 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. § 291.101 What definitions apply

to this part? Retained in its entirety in BSEE, chapter II. 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. § 291.102 May I call the MMS

Hotline to informally resolve anallegation that open and nondiscriminatory access was denied? Retained in its entirety in BSEE, chapter II. This section addresses open and nondiscriminatory access to oil andgas pipelines under OCSLA. Offshore operations are under the authority of BSEE.

§ 291.103 May I use alternative

dispute resolution to informally resolve an allegation that open and nondiscriminatory access

was denied? Retained in its entirety in BSEE, chapter II. This section addresses open and nondiscriminatory access to oil andgas pipelines under OCSLA. Offshore operations are under the authority of BSEE.

§ 291.104 Who may file a complaint or a third-party brief? Retained in its entirety in BSEE, chapter II. This section addresses open and nondiscriminatory access to oil andgas 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. This section addresses open and nondiscriminatory access to oil andgas pipelines under OCSLA. Offshore operations are under the authority of BSEE.§ 291.106 How do I file a complaint? Retained in its entirety in BSEE, chapter II. This section addresses open and nondiscriminatory access to oil andgas pipelines under OCSLA. Offshore operations are under the authority of BSEE. § 291.107 How do I answer a

complaint? Retained in its entirety in BSEE, chapter II. This section addresses open and nondiscriminatory access to oil andgas pipelines under OCSLA. Offshore operations are under the authority of BSEE.§ 291.108 How do I pay the processing fee? Retained in its entirety in BSEE, chapter II. This section addresses open and nondiscriminatory access to oil andgas pipelines under OCSLA. Offshore operations are under the authority of BSEE. § 291.109 Can I ask for a fee

waiver or a reduced processing

fee? Retained in its entirety in BSEE, chapter II. This section addresses open and nondiscriminatory access to oil andgas pipelines under OCSLA. Offshore operations are under the authority of BSEE. § 291.110 Who may MMS require

to produce information? Retained in its entirety in BSEE, chapter II. This section addresses open and nondiscriminatory access to oil andgas pipelines under OCSLA. Offshore operations are under the authority of BSEE. § 291.111 How does MMS treat

the confidential information I provide? Retained in its entirety in BSEE, chapter II. This section addresses open and nondiscriminatory access to oil andgas pipelines under OCSLA. Offshore operations are under the authority of BSEE. § 291.112 What process will MMS

follow in rendering a decision on whether a grantee or transporterhas provided open and nondiscriminatory access? Retained in its entirety in BSEE, chapter II. This section addresses open and nondiscriminatory access to oil andgas pipelines under OCSLA. Offshore operations are under the authority of BSEE.

§ 291.113 What actions may MMS

take to remedy denial of open and nondiscriminatory access? Retained in its entirety in BSEE, chapter II. This section addresses open and nondiscriminatory access to oil andgas pipelines under OCSLA. Offshore operations are under the authority of BSEE. § 291.114 How do I appeal to the

IBLA? Retained in its entirety in BSEE, chapter II. This section addresses open and nondiscriminatory access to oil andgas pipelines under OCSLA. Offshore operations are under the authority of BSEE.§ 291.115 How do I exhaust administrative remedies? Retained in its entirety in BSEE, chapter II. This section addresses open and nondiscriminatory access to oil andgas pipelines under OCSLA. Offshore operations are under the authority of BSEE.

Procedural Matters

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

This direct final rule is not a significant rule as determined by the Office of Management and Budget (OMB) and is not subject to review

under E.O. 12866. This direct final rule reorganizes the title 30 CFR chapter II regulations; this rule does not change existing regulatory requirements. (1) This direct final rule will not have
an annual effect of $100 million or more on the economy. It will not adversely affect in a material way the economy, productivity, competition: jobs; the environment; public health or safety; or state, local, or Tribal governments or

communities.

(2) This direct final rule will not create a serious inconsistency or
otherwise interfere with an action taken or planned by another agency. (3) This direct final rule will not alter the budgetary effects of entitlements, grants, user fees, or loan programs or the rights or obligations of their recipients.

(4) This direct final rule will not raise novel legal or policy issues arising out of legal mandates, the President’s priorities, or the principles set forth in

E.O. 12866.

Regulatory Flexibility Act

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


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

Small Business Regulatory Enforcement

Fairness Act

This direct final rule is not a major
rule under the Small Business Regulatory Enforcement Fairness Act (5

U.S.C. 801 et seq. ). This direct final rule:

a. Will not have an annual effect on the economy of $100 million or more.

b. Will not cause a major increase in costs or prices for consumers; individual industries; Federal, state, or local government agencies; or geographic regions.

c. Will not have significant adverse effects on competition, employment, investment, productivity, innovation, or the ability of U.S.-based enterprises to compete with foreign-based enterprises.

The requirements apply to all entities operating on the OCS. This direct final rule reorganizes the title 30 CFR chapter II regulations and does not change existing regulatory requirements.

Unfunded Mandates Reform Act of 1995

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

U.S.C. 1501 et seq. ) is not required.

Takings Implication Assessment (E.O. 12630)

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

Federalism (E.O. 13132)

Under the criteria in E.O. 13132, this
direct final rule does not have federalism implications. This direct final rule will not substantially and directly affect the relationship between the Federal and State governments. To
the extent that State and local governments have a role in OCS activities, this direct final rule will not
affect that role. A Federalism Assessment is not required. Civil Justice Reform (E.O. 12988)

This direct final rule complies with the requirements of E.O. 12988. Specifically, this rule:

(a) Meets the criteria of section 3(a) requiring that all regulations be
reviewed to eliminate errors and ambiguity and be written to minimize litigation; and

(b) Meets the criteria of section 3(b)(2) requiring that all regulations be written in clear language and contain clear legal
standards.

Consultation With Indian Tribes (E.O. 13175)

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

Paperwork Reduction Act (PRA) of 1995

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

National Environmental Policy Act of

1969

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

Data Quality Act

In developing this rule, we did not conduct or use a study, experiment, or survey requiring peer review under the Data Quality Act (Pub. L. 106–554, app.
C section 515, 114 Stat. 2763, 2763A– 153–154). Effects of the Nation’s Energy Supply (E.O. 13211)

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

List of Subjects

30 CFR Part 203

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

30 CFR Part 250

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

30 CFR Part 251

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

30 CFR Part 252

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

30 CFR Part 254

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

30 CFR Part 256

Administrative practice and procedure, Continental shelf, Environmental protection, Government contracts, Intergovernmental relations, Oil and gas exploration, Public lands—mineral resources, Public lands—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.

30 CFR Part 282

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


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and recordkeeping requirements, Surety
bonds.

30 CFR Part 290

Administrative practice and procedure.

30 CFR Part 291

Administrative practice and procedure.

30 CFR Part 519

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

30 CFR Part 550

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

30 CFR Part 551

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

30 CFR Part 552

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

30 CFR Part 553

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

30 CFR Part 556

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

30 CFR Part 559

Continental shelf, Government contracts, Mineral royalties, Oil and gas exploration, Public lands—mineral

resources. 30 CFR Part 560

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

30 CFR Part 570

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

resources.

30 CFR Part 580

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

30 CFR Part 581

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

30 CFR Part 582

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

bonds.

30 CFR Part 585

Continental shelf, Environmental protection, Incorporation by reference,

Public lands.

30 CFR Part 590

Administrative practice and procedure.

Dated: August 18, 2011.

Ned Farquhar,

Deputy Assistant Secretary—Land and Minerals Management.

For the reasons stated in the preamble, under the authority of 5

U.S.C. 901 et seq., the Bureau of Safety and Environmental Enforcement (BSEE) reassigns chapter II and Bureau of Ocean Energy Management (BOEM) establishes chapter V as follows:

**TITLE 30—MINERAL RESOURCES**

■ 1. Chapter II is revised to read as

follows: **CHAPTER II—BUREAU OF SAFETY AND ENVIRONMENTAL ENFORCEMENT,** 

**DEPARTMENT OF THE INTERIOR**

**SUBCHAPTER A—MINERALS REVENUE**

**MANAGEMENT**

Part

203 RELIEF OR REDUCTION IN ROYALTY

RATES

219 RESERVED

**SUBCHAPTER B—OFFSHORE**

250 OIL AND GAS AND SULPHUR

OPERATIONS IN THE OUTER

CONTINENTAL SHELF

251 GEOLOGICAL AND GEOPHYSICAL (G&G) EXPLORATIONS OF THE OUTER

CONTINENTAL SHELF 252 OUTER CONTINENTAL SHELF (OCS)

OIL AND GAS INFORMATION

PROGRAM

253 RESERVED

254 OIL–SPILL RESPONSE REQUIREMENTS FOR FACILITIES

LOCATED SEAWARD OF THE COAST

LINE

256 LEASING OF SULPHUR OR OIL AND

GAS IN THE OUTER CONTINENTAL

SHELF

259 RESERVED

260 RESERVED

270 NONDISCRIMINATION IN THE

OUTER CONTINENTAL SHELF

280 RESERVED

281 RESERVED

282 OPERATIONS IN THE OUTER

CONTINENTAL SHELF FOR MINERALS OTHER THAN OIL, GAS, AND

SULPHUR

285 RESERVED

**SUBCHAPTER C—APPEALS**

290 APPEAL PROCEDURES

291 OPEN AND NONDISCRIMINATORY

ACCESS TO OIL AND GAS PIPELINES

UNDER THE OUTER CONTINENTAL

SHELF LANDS ACT

**SUBCHAPTER A—MINERALS REVENUE**

**MANAGEMENT**

**PART 203—RELIEF OR REDUCTION IN**
**ROYALTY RATES**

**Subpart A—General Provisions**

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

information?

**Subpart B—OCS Oil, Gas, and Sulfur**

**General**

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

Relief

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


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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?

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

203.60 Who may apply for royalty relief on a case-by-case basis in deep water in the

Gulf of Mexico or offshore of Alaska? 203.61 How do I assess my chances for getting relief? 203.62 How do I apply for relief? 203.63 Does my application have to include

all leases in the field? 203.64 How many applications may I file on a field or a development project? 203.65 How long will BSEE take to evaluate my application? 203.66 What happens if BSEE does not act

in the time allowed?

203.67 What economic criteria must I meet to get royalty relief on an authorized field or project? 203.68 What pre-application costs will BSEE consider in determining economic viability? 203.69 If my application is approved, what royalty relief will I receive? 203.70 What information must I provide after BSEE approves relief?

203.71 How does BSEE allocate a field’s suspension volume between my lease and other leases on my field? 203.72 Can my lease receive more than one suspension volume? 203.73 How do suspension volumes apply to natural gas?

203.74 When will BSEE reconsider its

determination? 203.75 What risk do I run if I request a

redetermination? 203.76 When might BSEE withdraw or reduce the approved size of my relief? 203.77 May I voluntarily give up relief if conditions change? 203.78 Do I keep relief approved by BSEE under this part for my lease, unit or project if prices rise significantly? 203.79 How do I appeal BSEE’s decisions related to royalty relief for a deepwater lease or a development or expansion project? 203.80 When can I get royalty relief if I am not eligible for royalty relief under other sections in the subpart?

Required Reports

203.81 What supplemental reports do royalty-relief applications require? 203.82 What is BSEE’s authority to collect

this information?

203.83 What is in an administrative information report?

203.84 What is in a net revenue and relief justification report? 203.85 What is in an economic viability and relief justification report?

203.86 What is in a G&G report? 203.87 What is in an engineering report? 203.88 What is in a production report? 203.89 What is in a cost report?

203.90 What is in a fabricator’s confirmation report? 203.91 What is in a post-production development report? **Subpart C—Federal and Indian Oil [Reserved]** 

**Subpart D—Federal and Indian Gas [Reserved]** 

**Subpart E—Solid Minerals, General [Reserved]** 

**Subpart F [Reserved]**

**Subpart G—Other Solid Minerals [Reserved]**

**Subpart H—Geothermal Resources [Reserved]** 

**Subpart I—OCS Sulfur [Reserved]**

Authority: 25 U.S.C. 396 et seq.; 25 U.S.C.

396a et seq.; 25 U.S.C. 2101 et seq.; 30 U.S.C.

181 et seq.; 30 U.S.C. 351 et seq.; 30 U.S.C.

1001 et seq.; 30 U.S.C. 1701 et seq.; 31 U.S.C. 9701; 42 U.S.C. 15903–15906; 43 U.S.C. 1301 et seq.; 43 U.S.C. 1331 et seq.; and 43 U.S.C.

1801 et seq.

**Subpart A—General Provisions**

**§ 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: (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 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. Qualified well means either aqualified 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 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. Anultra-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, 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, Propose an expansion project and can demonstrate your project is uneconomic without royalty relief, 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). (c) Located in a designated GOM deep water

area and acquired in a lease sale held before November 28, 1995 (Pre-Act lease), Are on a field from which no current pre-Act lease produced (other than test production) before November 28, 1995, (Authorized field,) A royalty suspension for a minimum production volume plus any additional volume needed to make the field economic (see §§ 203.60 through 203.79). (d) Located in a designated GOM deep water

area and acquired in a lease sale held after November 28, 2000, Propose a development project and can demonstrate that the suspension volume, if any,for your lease is not enough to make development economic, A royalty suspension for a minimum production volume plus any additional volume needed to make your project economic (see §§ 203.60 through 203.79).(e) Where royalty relief would recover significant additional resources or, offshore Alaska or in certain areas of the GOM, would enable development, Are not eligible to apply for end-of-life or deep water royalty relief, but show us you meet certain eligibility conditions, A royalty modification in size, duration, orform that makes your lease or project economic (see § 203.80).

(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, 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, A royalty suspension for a volume of gas produced from successful deep and ultra-deep wells, or, for certain unsuccessful deep andultra-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). (g) Located in a designated GOM shallow water

area, 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, 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). (h) Located in planning areas offshore Alaska, 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, foryour lease is not enough to make development economic, 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).

**§ 203.3 Do I have to pay a fee to request royalty relief?** 

When you submit an application or ask for a preview assessment, you must

include a fee to reimburse us for our costs of processing your application or assessment. Federal policy and law require us to recover the cost of services that confer special benefits to identifiable non-Federal recipients. The Independent Offices Appropriation Act (31 U.S.C. 9701), Office of Management and Budget Circular A–25, and the Omnibus Appropriations Bill (Pub. L. 104–134, 110 Stat. 1321, April 26, 1996)
authorize us to collect these fees.

(a) We will specify the necessary fees for each of the types of royalty relief applications and possible BSEE audits
in a Notice to Lessees. We will periodically update the fees to reflect changes in costs, as well as provide other information necessary to administer royalty relief.

(b) You must file all payments electronically through the Pay.gov Web site and you must include a copy of the Pay.gov confirmation receipt page with your application or assessment. The Pay.gov Web site may be accessed through a link on the BSEE Offshore

Web site at: http://www.bsee.gov/ offshore/ homepage or directly through Pay.gov at: https://www.pay.gov/ paygov/.

**§ 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 approvalprovisions 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 §§ 203.51, 203.62, and 203.81 through 203.89 for applications for royalty relief.

Information elements End-of-life
lease Deep water

Expansion

project Pre-act
lease Development project

(1) Administrative information report ............................................................................... X X X X (2) Net revenue and relief justification report (prescribed format) .................................. X .................. ......

............ ......................(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) ........................................................................... ................ ...... X X X (4) G&G report ................................................................................................................. ...................... X X X (5) Engineering report ...................................................................................................... ... ................... X X X (6) Production report ........................................................................................................ .. .................... X X X (7) Deep water cost report .............................................................................................. ....... ............... X X X

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

Confirmation elements End-of-life
lease Deep water

Expansion

project Pre-act
lease Development project

(1) Fabricator’s confirmation report ................................................................................. .......... ............ X X X (2) Post-production development report approved by an independent certified public

accountant (CPA) * * * ............................................................................................... ............ .......... X X X

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

Approval conditions End-of-life
lease Deep water

Expansion Pre-act
lease Development project

(1) At least 12 of the last 15 months have the required level of production .................. X .................. ..............

.... ...................... (2) Already producing ...................................................................................................... X ..

................ .................. ...................... (3) A producible well into a reservoir that has not produced before ............................... ...................... X X X (4) Royalties for qualifying months exceed 75 percent of net revenue (NR) ................. X .................. .................

. ...................... (5) Substantial investment on a pre-Act lease ( e.g., platform, subsea template) ........... ...................... .................. .................. ...................... (6) Determined to be economic only with relief ............................................................... .................. .... X X X

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

decision.

Redetermination conditions End-of-life
lease Deep water

Expansion

project Pre-act
lease Development project

(1) After 12 months under current rate, criteria same as for approval ........................... X .................. ...........

....... ...................... (2) For material change in geologic data, prices, costs, or available technology ........... ...................... X X X

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


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Relief rate and volume, subject to certain conditions End-of-life
lease Deep water

Expansion

project Pre-act
lease Development project

(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 .... X .................. .................. ....

.................. (2) Qualifying amount is the average monthly production for 12 qualifying months ...... X .................. .................. ...

...................(3) Zero royalty rate on the suspension volume and the original lease rate on additional production ........................................................................................................... ... ................... X X X (4) Suspension volume is at least 17.5, 52.5 or 87.5 million barrels of oil equivalent

(MMBOE) ..................................................................................................................... ... ................... .................. X ...................... (5) Suspension volume is at least the minimum set in the Notice of Sale, the lease, or

the regulations .............................................................................................................. .. .................... X .................. X (6) Amount needed to become economic ....................................................................... .................... .. X X X

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

Full royalty resumes when End-of-life
lease Deep water

Expansion

project Pre-act
lease Development project

(1) Average NYMEX price for last 12 months is at least 25 percent above the average for the qualifying months. ..................................................................................... X ..........

........ .................. ......................(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 ................................ ...................... X X ........

.............. (3) Average prices for designated periods exceed levels we specify in the Notice of

Sale or the lease .......................................................................................................... .... .................. X .................. X

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

Relief withdrawn or reduced End-of-life
lease Deep water

Expansion

project Pre-act
lease Development project

(1) If recipient requests .................................................................................................... X X X X (2) Lease royalty rate is at the effective rate for 12 consecutive months ....................... X .................. ...........

....... ...................... (3) Conditions occur that we specified in the approval letter in individual cases ........... X .................. ...............

... ......................(4) Recipient does not submit post-production report that compares expected to actual costs ..................................................................................................................... . ...................... X X X (5) Recipient changes development system ................................................................... .................... .. X X X (6) Recipient excessively delays starting fabrication ....................................................... ................... ... X X X (7) Recipient spends less than 80 percent of proposed pre-production costs prior to

start of production ........................................................................................................ .... .................. X X X (8) Amount of relief volume is produced ......................................................................... ............... ....... X X X

**§ 203.5 What is BSEE’s authority to collect**

**information?**

(a) The Office of Management and Budget (OMB) has approved the information collection requirements in this part under 44 U.S.C. 3501 et seq., and assigned OMB Control Number
1010–0071. The title of this information collection is ‘‘30 CFR part 203, Relief or Reduction in Royalty Rates.’’

(b) BSEE collects this information to
make decisions on the economic viability of leases requesting a suspension or elimination of royalty or net profit share. Responses are required to obtain a benefit or are mandatory according to 43 U.S.C. 1331 et seq. BSEE will protect information considered proprietary under applicable law and under regulations at § 203.61, ‘‘How do I assess my chances for getting relief?’’ and 30 CFR 250.197, ‘‘Data and

information to be made available to the public or for limited inspection.’’

(c) An agency may not conduct or sponsor, and a person is not required to respond to a collection of information unless it displays a currently valid OMB

control number.

(d) Send comments regarding any aspect of the collection of information under this part, including suggestions for reducing the burden, to the

Information Collection Clearance Officer, Bureau of Safety and Environmental Enforcement, 381 Elden Street, Herndon, VA 20170.

**Subpart B—OCS Oil, Gas, and Sulfur**

**General**

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

**§ 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. **§ 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, 35 BCF. (2) A sidetrack with a sidetrack measured depth of at least 20,000 feet, 35 BCF. (3) An ultra-deep short sidetrack that is a phase 2 ultra-deep well, 4 BCF plus 600 MCF times sidetrack measured depth (rounded to the nearest 100 feet) but no

more than 25 BCF. (4) An ultra-deep short sidetrack that is a phase 3 ultra-deep well, 0 BCF.

(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, 10 BCF.

(ii) An ultra-deep short sidetrack, 4 BCF plus 600 MCF times sidetrack measured depth (rounded to the nearest 100 feet) but no more than 10 BCF.

(c) Lessees may request a refund of or recoup royalties paid on productionfrom 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 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 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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which is 16,000 feet TVD SS. Your 16,000-

foot well earns no RSV because it is on a lease that already has a producing well at least 18,000 feet subsea (see § 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 thequalified 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 becauseit 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 noRSV 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 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 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 onequalified 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 incases 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 (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. (2) $4.55 per MMBtu, (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. (3) $4.08 per MMBtu, (i) The first 20 BCF of RSV earned by a well that is located on a nonconverted lease issued in OCS Lease Sale 178.


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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.

(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 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 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, Has a qualified deep well or qualified phase 1 ultra-deep well, earns an RSV specified in paragraph (b) of

this section.(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 with a perforated interval whose top is 18,000 feet TVD SS or deeper or a qualified phase 1 ultra-deep well, earns an RSV specified in paragraph (c) of

this section.

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

If you have a qualified deep well or a qualified phase 1 ultra-deep 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 from

15,000 to less than 18,000 feet TVD SS, 15 BCF.

(2) A sidetrack with a perforated interval the top of which is from

15,000 to less than 18,000 feet TVD SS, 4 BCF plus 600 MCF times sidetrack measured depth (rounded to the nearest 100 feet) but no more than 15 BCF. (3) An original well with a perforated interval the top of which is at least

18,000 feet TVD SS, 25 BCF.

(4) A sidetrack with a perforated interval the top of which is at least

18,000 feet TVD SS, 4 BCF plus 600 MCF times sidetrack measured depth (rounded to the nearest 100 feet) but no more than 25 BCF.

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

SS.

If you have a qualified deep well or a qualified phase 1 ultra-deep well
that 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, 0 BCF.

(2) An original well with a perforated interval the top of which is 18,000

feet TVD SS or deeper, 10 BCF.

(3) A sidetrack with a perforated interval the top of which is 18,000 feet

TVD SS or deeper, 4 BCF plus 600 MCF times sidetrack measured depth (rounded to the nearest 100 feet) but no more than 10 BCF.

(d) Lessees may request a refund of or recoup royalties paid on production from qualified wells on a lease that is located in water entirely deeper than 200 meters but entirely less than 400 meters deep that:

(1) Occurs before December 18, 2008;
and

(2) Is subject to application of an RSV under either § 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 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); (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, your lease cannot earn an RSV under § 203.41 as a result of drilling any subsequent deep wells or phase 1 ultra-deep wells. (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, 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. (c) A qualified deep well or qualified phase 1 ultra-deep well on your

lease is within a unitized portion of your lease, 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.(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, 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. (e) You earn an RSV under § 203.41, that RSV is in addition to any RSS for your lease under § 203.45 that

results from a different wellbore. (f) Your lease earns an RSV under § 203.41 and later produces from a

well that is not a qualified well, the RSV is not forfeited or terminated, but you may not apply the RSV under § 203.41 to production from the non-qualified well. (g) You qualify for an RSV under paragraphs (b) or (c) of § 203.41, you still owe minimum royalties or rentals in accordance wit h your

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

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

**§ 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. (b) This paragraph applies to any lease with a qualified deep well or qualified phase 1 ultra-deep well whenno 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 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.

(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 caseswhere 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 (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 qualifieddeep 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, 0.8 BCFE plus 120 MCFE times sidetrack measured depth (rounded to the nearest 100 feet) but no more than 5 BCFE.

(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, 2 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.

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 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 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 gasand 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 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, before December 18, 2008, $10.15 per MMBtu, adjusted annually after calendar year 2007 for inflation. (2) Partly or entirely less than 200

meters deep, after December 18, 2008, $4.55 per MMBtu, adjusted annually after calendar year 2007 for inflation unless the lease terms prescribe a different price threshold. (3) Entirely more than 200 meters

and entirely less than 400 meters deep, on any date, $4.55 per MMBtu, adjusted annually after calendar year 2007 for inflation unless the lease terms prescribe a different price threshold.

(b) Determine the threshold price for any calendar year after 2007 by adjusting the threshold price in the previous year by the percentage that the implicit price deflator for the gross domestic product, as published by the Department of Commerce, changed during the calendar year.

(c) You must pay any royalty due
under this section no later than March 31 of the year following the calendar year for which you owe royalty. If you do not pay by that date, you must pay late payment interest under 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.

**§ 203.49 May I substitute the deep gas drilling provisions in this part for the deep**  **gas royalty relief provided in my lease**

**terms?**

(a) You may exercise an option to replace the applicable lease terms for royalty relief related to deep-well drilling with those in § 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. (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.

Royalty Relief for End-of-Life Leases

**§ 203.50 Who may apply for end-of-life royalty relief?** 

You may apply for royalty relief in

two situations.

(a) Your end-of-life lease (as defined in § 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 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 What criteria must I meet to get**

**relief?**

(a) To qualify for relief, you must demonstrate that the sum of royalty payments over the 12 qualifying months exceeds 75 percent of the sum of net revenues (before-royalty revenues minus allowable costs, as defined in § 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?**

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 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. **§ 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.


### 64479 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

**§ 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 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. (2) We cannot evaluate your application

for a valid reason, such as missing

vital information or inconsistent or inconclusive supporting data, Add another 30 days. We may add more than 30 days, but only if you agree.

(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, You get the minimum suspension volumes specified in § 203.69, Abide by §§ 203.70 and 203.76. (b) An expansion project, You get a royalty suspension for the first year of production, Abide by §§ 203.70 and 203.76. (c) A development project, 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.

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

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

**§ 203.68 What pre-application costs will BSEE consider in determining economic**  **viability?**

(a) We will not consider ineligible costs as set forth in § 203.89(h) in determining economic viability for purposes of royalty relief.

(b) We will consider sunk costs according to the following table.

We will . . . When determining . . .

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

well on each lease, Whether a development project or an expansion project needs relief to become economic.

**§ 203.69 If my application is approved, what royalty relief will I receive?** 

If we approve your application, subject to certain conditions, we will not collect royalties on a specified suspension volume for your field, development project, or expansion project. Suspension volumes include volumes allocated to a lease under an approved unit agreement, but exclude any volumes of production that are not normally royalty-bearing under the lease


### 64480 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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. BSEE Director may grant you an extension under § 203.79(c) for up to 6 months. (b) Post-production report. Within 120 days after the start of productionthat is subject to the approved royalty suspension volume. 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?**

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.


### 64481 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

If . . . 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, 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 afterthe field has produced the approved relief 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 yourauthorized field still needs additional royalty suspension volume, that volume will be at least the combined royalty suspension volume to which alladded leases on the field are entitled, or the minimum suspension volume of the authorized field, whichever is greater, (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 § 203.69for your authorized field, but you will not owe royalty on production from the eligible lease until it has produced the volume applicable under 30
CFR 560.114. (4) We assign another operator’s

lease to your field while we are evaluating your application, We will change your field’s minimum suspensionvolume provided the assigned lease joins the application and is entitled to a larger minimum suspension volume, (i) You both toll the time period for evaluation untilboth 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. (5) We reassign a well on a pre-Act,

eligible, or royalty suspension lease from field A to field B, The past production from the well counts toward the royalty suspension volume that we grant under § 203.69 to field B, For any field based relief, the past production forthat 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 volume under § 203.62 in two

circumstances.

(a) Each field that includes your leasemay receive a separate royaltysuspension volume, if it meets the evaluation criteria of § 203.67.

(b) An expansion project on yourlease 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 gasproduction under the royaltysuspension volume as follows: 5.62 thousand cubic feet of natural gas, measured in accordance with 30 CFR part 250, subpart L, equals one barrel of oil equivalent.

**§ 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


### 64482 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, andyou 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 fabricationconfirmation 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.

For . . . The base price threshold is . . .

(1) Pre-Act leases in the GOM, set by statute.(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, indicated in your original lease agreement or, if none, those in the Notice of Sale under which your lease was issued.

(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, the threshold set by statute for pre-Act leases.


### 64483 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

(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 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.

Required reports End-of-life
lease Deep water

Expansion

project Pre-act lease Development project

(1) Administrative information Report .............................................................. X X X X (2) Net revenue & relief justification report ...................................................... X ........................ ..

...................... ........................


### 64484 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

Required reports End-of-life
lease Deep water

Expansion

project Pre-act lease Development project

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

(b) You must certify that all information in your application,fabricator’s confirmation and 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.

**§ 203.82 What is BSEE’s authority to**

**collect this information?**

The Office of Management and Budget (OMB) approved the information collection requirements in part 203
under 44 U.S.C. 3501 et seq., and assigned OMB control number 1010–

0071.

(a) We use the information to determine whether royalty relief will result in production that wouldn’t otherwise occur. We rely largely on your
information to make these
determinations.

(1) Your application for royalty relief must contain enough information on finances, economics, reservoirs, G&G characteristics, production, and engineering estimates for us to
determine whether:

(i) We should grant relief under the law, and (ii) The requested relief will ultimately recover more resources and return a reasonable profit on project

investments.

(2) Your fabricator confirmation and post-production development reports must contain enough information for us to verify that your application reasonably represented your plans.

(b) Applicants (respondents) are Federal OCS oil and gas lessees. Applications are required to obtain or retain a benefit. Therefore, if you apply for royalty relief, you must provide this information. We will protect information considered proprietary under applicable law and under regulations at § 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); (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;


### 64485 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

(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.

**§ 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 (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 surveylines 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 surveylines 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 (R

o) and the resistivity of the undisturbed formation (Rt), and

(iv) The 5-inch porosity logs show pay zones and pay counts and labeled points used in establishing reservoir porosity or labeled points showing values used in calculating reservoir porosity such as bulk density or transit time;

(2) Digital copies of all well logs spudded before December 1, 1995;

(3) Core data, if available; (4) Well correlation sections; (5) Pressure data; (6) Production test results; (7) Pressure-volume-temperature analysis, if available; and

(8) A table listing the wells and completions, and indicating which sands and fault blocks will be targeted for completion or recompletion.

(c) Map interpretations which
includes for each reservoir in the field: (1) Structure maps consisting of top and base of sand maps showing well and seismic shot point locations;

(2) Isopach maps for net sand, net oil, net gas, all with well locations;

(3) Maps indicating well surface and bottom hole locations, location of development facilities, and shot points;
and

(4) An explanation for excluding the reservoirs you are not planning to develop.

(d) Reservoir-specific data which
includes:

(1) Probability of reservoir occurrence with hydrocarbons;

(2) Probability the hydrocarbon in the reservoir is all oil and the probability it is all gas;

(3) Distributions or point estimates (accompanied by explanations of why distributions less appropriately reflect the uncertainty) for the parameters used
to estimate reservoir size, i.e., acres and net thickness;

(4) Most likely values for porosity, salt water saturation, volume factor for oil formation, and volume factor for gas formation;

(5) Distributions or point estimates (accompanied by explanations of why distributions less appropriately reflect the uncertainty) for recovery efficiency (in percent) and oil or gas recovery (in stock-tank-barrels per acre-foot or in thousands of cubic feet per acre foot);

(6) A gas/oil ratio distribution or point estimate (accompanied by explanations of why distributions less appropriately reflect the uncertainty) for each
reservoir;

(7) A yield distribution or point estimate (accompanied by explanations of why distributions less appropriately reflect the uncertainty) for each gas reservoir; and

(8) Reserve or resource distribution by

reservoir.

(e) Aggregated reserve and resource
data which includes:

(1) The aggregated distributions for reserves and resources (in BOE) and oil fraction for your field computed by the resource module of our RSVP model;

(2) A description of anticipated hydrocarbon quality (i.e., specific gravity); and

(3) The ranges within the aggregated
distribution for reserves and resources that define the development and production scenarios presented in the engineering and production reports. Typically there will be three ranges specified by two positive reserve and resource points on the aggregated distribution. The range at the low end
of the distribution will be associated with the conservative development and production scenario; the middle range


### 64486 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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?**

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 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 consistentwith 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 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 whenproduction 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).


### 64487 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

**Subpart C—Federal and Indian Oil [Reserved]** 

**Subpart D—Federal and Indian Gas [Reserved]** 

**Subpart E—Solid Minerals, General [Reserved]** 

**Subpart F—[Reserved]**

**Subpart G—Other Solid Minerals [Reserved]** 

**Subpart H—Geothermal Resources [Reserved]** 

**Subpart I—OCS Sulfur [Reserved]**

**PART 219—[RESERVED]**

**Subchapter B—Offshore**

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

**Subpart A—General**

Authority and Definition of Terms

Sec. 250.101 Authority and applicability. 250.102 What does this part do?

250.103 Where can I find more information about the requirements in this part? 250.104 How may I appeal a decision made under BSEE regulations?

250.105 Definitions.

Performance Standards

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

have on the lease term? 250.123 [Reserved] 250.124 Will BSEE approve gas injection into the cap rock containing a sulphur deposit? Fees

250.125 Service fees. 250.126 Electronic payment instructions.

Inspection of Operations

250.130 Why does BSEE conduct inspections? 250.131 Will BSEE notify me before conducting an inspection?

250.132 What must I do when BSEE conducts an inspection? 250.133 Will BSEE reimburse me for my expenses related to inspections?

Disqualification

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

Special Types of Approvals

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

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

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

250.151 How do I name facilities in the Pacific Region?

250.152 How do I name facilities in the Alaska Region? 250.153 Do I have to rename an existing facility or well? 250.154 What identification signs must I display? 250.160–250.167 [Reserved]

Suspensions

250.168 May operations or production be suspended? 250.169 What effect does suspension have on my lease? 250.170 How long does a suspension last? 250.171 How do I request a suspension? 250.172 When may the Regional Supervisor grant or direct an SOO or SOP? 250.173 When may the Regional Supervisor

direct an SOO or SOP? 250.174 When may the Regional Supervisor grant or direct an SOP? 250.175 When may the Regional Supervisor grant an SOO? 250.176 Does a suspension affect my royalty payment? 250.177 What additional requirements may the Regional Supervisor order for a suspension?

Primary Lease Requirements, Lease Term Extensions, and Lease Cancellations

250.180 What am I required to do to keep my lease term in effect? 250.181–250.185 [Reserved] Information and Reporting Requirements

250.186 What reporting information and report forms must I submit? 250.187 What are BSEE’s incident reporting requirements?

250.188 What incidents must I report to BSEE and when must I report them? 250.189 Reporting requirements for incidents requiring immediate
notification. 250.190 Reporting requirements for incidents requiring written notification.
250.191 How does BSEE conduct incident investigations? 250.192 What reports and statistics must I submit relating to a hurricane, earthquake, or other natural occurrence? 250.193 Reports and investigations of apparent violations. 250.194 How must I protect archaeological

resources?
250.195 What notification does BSEE require on the production status of
wells? 250.196 Reimbursements for reproduction and processing costs.
250.197 Data and information to be made available to the public or for limited inspection.

References

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

**Subpart B—Plans and Information**

General Information

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

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

250.282 Do I have to conduct post-approval monitoring?

Deepwater Operations Plans (DWOP)

250.286 What is a DWOP? 250.287 For what development projects

must I submit a DWOP?

250.288 When and how must I submit the Conceptual Plan? 250.289 What must the Conceptual Plan

contain? 250.290 What operations require approval of the Conceptual Plan?

250.291 When and how must I submit the

DWOP?
250.292 What must the DWOP contain? 250.293 What operations require approval

of the DWOP? 250.294 May I combine the Conceptual Plan

and the DWOP? 250.295 When must I revise my DWOP?

**Subpart C—Pollution Prevention and**

**Control**

250.300 Pollution prevention.


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250.301 Inspection of facilities.

**Subpart D—Oil and Gas Drilling Operations**

General Requirements

250.400 Who is subject to the requirements of this subpart? 250.401 What must I do to keep wells under
control?
250.402 When and how must I secure a
well? 250.403 What drilling unit movements must I report? 250.404 What are the requirements for the
crown block? 250.405 What are the safety requirements for diesel engines used on a drilling rig? 250.406 What additional safety measures must I take when I conduct drilling operations on a platform that has producing wells or has other hydrocarbon flow?
250.407 What tests must I conduct to
determine reservoir characteristics? 250.408 May I use alternative procedures or equipment during drilling operations? 250.409 May I obtain departures from these drilling requirements?

Applying for a Permit to Drill

250.410 How do I obtain approval to drill
a well?
250.411 What information must I submit with my application? 250.412 What requirements must the location plat meet? 250.413 What must my description of well drilling design criteria address? 250.414 What must my drilling prognosis
include? 250.415 What must my casing and cementing programs include?
250.416 What must I include in the diverter and BOP descriptions? 250.417 What must I provide if I plan to use a mobile offshore drilling unit (MODU)?
250.418 What additional information must I submit with my APD?

Casing and Cementing Requirements

250.420 What well casing and cementing requirements must I meet? 250.421 What are the casing and cementing requirements by type of casing string? 250.422 When may I resume drilling after cementing? 250.423 What are the requirements for pressure testing casing? 250.424 What are the requirements for prolonged drilling operations? 250.425 What are the requirements for pressure testing liners? 250.426 What are the recordkeeping requirements for casing and liner pressure tests? 250.427 What are the requirements for pressure integrity tests?
250.428 What must I do in certain cementing and casing situations?

Diverter System Requirements

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

tests?

Blowout Preventer (BOP) System Requirements
250.440 What are the general requirements for BOP systems and system components? 250.441 What are the requirements for a

surface BOP stack? 250.442 What are the requirements for a subsea BOP system? 250.443 What associated systems and related equipment must all BOP systems

include?

250.444 What are the choke manifold requirements? 250.445 What are the requirements for kelly valves, inside BOPs, and drill-string safety valves?

250.446 What are the BOP maintenance and inspection requirements? 250.447 When must I pressure test the BOP system? 250.448 What are the BOP pressure tests requirements? 250.449 What additional BOP testing requirements must I meet? 250.450 What are the recordkeeping requirements for BOP tests?

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

Drilling Fluid Requirements

250.455 What are the general requirements for a drilling fluid program? 250.456 What safe practices must the drilling fluid program follow?

250.457 What equipment is required to monitor drilling fluids? 250.458 What quantities of drilling fluids are required? 250.459 What are the safety requirements for drilling fluid-handling areas?

Other Drilling Requirements

250.460 What are the requirements for conducting a well test? 250.461 What are the requirements for directional and inclination surveys?250.462 What are the requirements for 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. 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 Tubing and wellhead equipment. 250.619 Wireline operations.

**Subpart G—[Reserved]**

**Subpart H—Oil and Gas Production Safety Systems** 

250.800 General requirements. 250.801 Subsurface safety devices. 250.802 Design, installation, and operation of surface production-safety systems. 250.803 Additional production system requirements. 250.804 Production safety-system testing

and records. 250.805 Safety device training. 250.806 Safety and pollution prevention equipment quality assurance requirements. 250.807 Additional requirements for subsurface safety valves and related equipment installed in high pressure high temperature (HPHT) environments. 250.808 Hydrogen sulfide.

**Subpart I—Platforms and Structures**

General Requirements for Platforms

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

Platform Approval Program

250.904 What is the Platform Approval Program? 250.905 How do I get approval for the installation, modification, or repair of my platform? 250.906 What must I do to obtain approval for the proposed site of my platform?

250.907 Where must I locate foundation

boreholes?

250.908 What are the minimum structural fatigue design requirements?

Platform Verification Program

250.909 What is the Platform Verification Program? 250.910 Which of my facilities are subject to the Platform Verification Program? 250.911 If my platform is subject to the Platform Verification Program, what

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

250.913 When must I resubmit Platform Verification Program plans?

250.914 How do I nominate a CVA? 250.915 What are the CVA’s primary responsibilities? 250.916 What are the CVA’s primary duties during the design phase? 250.917 What are the CVA’s primary duties during the fabrication phase? 250.918 What are the CVA’s primary duties during the installation phase?

Inspection, Maintenance, and Assessment of

Platforms

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

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

250.1000 General requirements.

250.1001 Definitions. 250.1002 Design requirements for DOI pipelines. 250.1003 Installation, testing, and repair requirements for DOI pipelines. 250.1004 Safety equipment requirements for DOI pipelines. 250.1005 Inspection requirements for DOI pipelines.

250.1006 How must I decommission and take out of service a DOI pipeline? 250.1007 What to include in applications. 250.1008 Reports. 250.1009 Requirements to obtain pipeline right-of-way grants. 250.1010 General requirements for pipeline right-of-way holders. 250.1011 [Reserved] 250.1012 Required payments for pipeline right-of-way holders. 250.1013 Grounds for forfeiture of pipeline right-of-way grants. 250.1014 When pipeline right-of-way grants expire.250.1015 Applications for pipeline right-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? 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 H 2 S?

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?

Financial Solvency Requirements

250.1495 How do I demonstrate financial solvency?
250.1496 How will BOEM determine if I am financially solvent? 250.1497 When will BOEM monitor my financial solvency?

**Subpart O—Well Control and Production Safety Training** 

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

**Subpart P—Sulphur Operations**

250.1600 Performance standard.

250.1601 Definitions. 250.1602 Applicability. 250.1603 Determination of sulphur deposit. 250.1604 General requirements. 250.1605 Drilling requirements.

250.1606 Control of wells.

250.1607 Field rules. 250.1608 Well casing and cementing. 250.1609 Pressure testing of casing. 250.1610 Blowout preventer systems and
system components. 250.1611 Blowout preventer systems tests, actuations, inspections, and

maintenance.
250.1612 Well-control drills. 250.1613 Diverter systems. 250.1614 Mud program. 250.1615 Securing of wells. 250.1616 Supervision, surveillance, and training. 250.1617 Application for permit to drill. 250.1618 Application for permit to modify.

250.1619 Well records.250.1620 Well-completion and 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? 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 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

### —W HERE 

### TO 

### F IND 

### I NFORMATION FOR 

### C ONDUCTING 

### O PERATIONS

For information about . . . Refer to . . .

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

**§ 250.103 Where can I find more information about the requirements in this**  **part?**

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

submissions to BSEE. **§ 250.104 How may I appeal a decision made under BSEE regulations?** 

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

**§ 250.105 Definitions.**

Terms used in this part will have the meanings given in the Act and as
defined in this section:

Act means the OCS Lands Act, as amended (43 U.S.C. 1331 et seq. ). Affected State means with respect to any program, plan, lease sale, or other activity proposed, conducted, or approved under the provisions of the Act, any State:

(1) The laws of which are declared, under section 4(a)(2) of the Act, to be
the law of the United States for the portion of the OCS on which such activity is, or is proposed to be, conducted;

(2) Which is, or is proposed to be, directly connected by transportation


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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 activities that are at least 50 years of age and that are of archaeological interest.

Attainment area means, for any air pollutant, an area that is shown by monitored data or that is calculated by air quality modeling (or other methods determined by the Administrator of EPA to be reliable) not to exceed any primary or secondary ambient air quality standards established by EPA.

Best available and safest technology (BAST) means the best available and safest technologies that the BSEE Director determines to be economically feasible wherever failure of equipment would have a significant effect on safety, health, or the environment.

Best available control technology (BACT) means an emission limitation based on the maximum degree of reduction for each air pollutant subject to regulation, taking into account energy, environmental and economic impacts, and other costs. The Regional Supervisor will verify the BACT on a case-by-case basis, and it may include reductions achieved through the application of processes, systems, and techniques for the control of each air pollutant.

Coastal environment means the physical, atmospheric, and biological components, conditions, and factors that interactively determine the productivity, state, condition, and quality of the terrestrial ecosystem from
the shoreline inward to the boundaries
of the coastal zone.

Coastal zone means the coastal waters (including the lands therein and thereunder) and the adjacent shorelands (including the waters therein and thereunder) strongly influenced by each other and in proximity to the shorelands
of the several coastal States. The coastal zone includes islands, transition and intertidal areas, salt marshes, wetlands,
and beaches. The coastal zone extends
seaward to the outer limit of the U.S.
territorial sea and extends inland from the shorelines to the extent necessary to control shorelands, the uses of which have a direct and significant impact on the coastal waters, and the inward boundaries of which may be identified by the several coastal States, under the authority in section 305(b)(1) of the Coastal Zone Management Act (CZMA)
of 1972.

Competitive reservoir means a reservoir in which there are one or more producible or producing well completions on each of two or more leases or portions of leases, with different lease operating interests, from which the lessees plan future production.

Correlative rights when used with respect to lessees of adjacent leases, means the right of each lessee to be afforded an equal opportunity to explore for, develop, and produce, without waste, minerals from a common source.

Data means facts and statistics, measurements, or samples that have not been analyzed, processed, or interpreted.

Departures mean approvals granted by the appropriate BSEE or BOEM representative for operating requirements/procedures other than those specified in the regulations found in this part. These requirements/ procedures may be necessary to control a well; properly develop a lease; conserve natural resources, or protect life, property, or the marine, coastal, or
human environment.

Development means those activities that take place following discovery of minerals in paying quantities, including but not limited to geophysical activity, drilling, platform construction, and operation of all directly related onshore support facilities, and which are for the purpose of producing the minerals
discovered.

Development geological and geophysical (G&G) activities mean those G&G and related data-gathering activities on your lease or unit that you conduct following discovery of oil, gas, or sulphur in paying quantities to detect or imply the presence of oil, gas, or sulphur in commercial quantities.

Director means the Director of BSEE of the U.S. Department of the Interior,
or an official authorized to act on the
Director’s behalf.

District Manager means the BSEE officer with authority and responsibility for operations or other designated program functions for a district within a BSEE Region.

Easement means an authorization for a nonpossessory, nonexclusive interest in a portion of the OCS, whether leased or unleased, which specifies the rights
of the holder to use the area embraced
in the easement in a manner consistent
with the terms and conditions of the granting authority.

Eastern Gulf of Mexico means all OCS
areas of the Gulf of Mexico the BOEM Director decides are adjacent to the
State of Florida. The Eastern Gulf of
Mexico is not the same as the Eastern Planning Area, an area established for
OCS lease sales.

Emission offsets mean emission reductions obtained from facilities, either onshore or offshore, other than the facility or facilities covered by the proposed Exploration Plan (EP) or Development and Production Plan (DPP).

Enhanced recovery operations mean pressure maintenance operations,


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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 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 islandused 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.

H

2 S absent means: (1) Drilling, logging, coring, testing, or producing operations have confirmed
the absence of H 2 S in concentrations that could potentially result in atmospheric concentrations of 20 ppm
or more of H2 S; or

(2) Drilling in the surrounding areas and correlation of geological and seismic data with equivalent stratigraphic units have confirmed an
absence of H2 S throughout the area to be
drilled.

H

2 S present means drilling, logging, coring, testing, or producing operations have confirmed the presence of H2 S in
concentrations and volumes that could potentially result in atmospheric concentrations of 20 ppm or more of

H 2 S.

H

2 S unknown means the designation of a zone or geologic formation where neither the presence nor absence of H2 S
has been confirmed.

Human environment means the physical, social, and economic components, conditions, and factors that interactively determine the state, condition, and quality of living conditions, employment, and health of those affected, directly or indirectly, by activities occurring on the OCS.

Interpreted geological information means geological knowledge, often in the form of schematic cross sections, 3- dimensional representations, and maps, developed by determining the geological significance of data and analyzed geological information.

Interpreted geophysical information means geophysical knowledge, often in the form of schematic cross sections, 3- dimensional representations, and maps, developed by determining the geological significance of geophysical data and analyzed geophysical information.

Lease means an agreement that is
issued under section 8 or maintained
under section 6 of the Act and that authorizes exploration for, and development and production of,
minerals. The term also means the area covered by that authorization, whichever the context requires.

Lease term pipelines mean those pipelines owned and operated by a lessee or operator that are completely
contained within the boundaries of a single lease, unit, or contiguous (not cornering) leases of that lessee or
operator.

Lessee means a person who has
entered into a lease with the United States to explore for, develop, and produce the leased minerals. The term
lessee also includes the 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.,


### 64494 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

an action that will have a significant impact on the quality of the human environment requiring preparation of an environmental impact statement under section 102(2)(C) of the National Environmental Policy Act).

Marine environment means the physical, atmospheric, and biological components, conditions, and factors that interactively determine the productivity, state, condition, and quality of the marine ecosystem. These include the waters of the high seas, the contiguous zone, transitional and intertidal areas, salt marshes, and
wetlands within the coastal zone and on
the OCS.

Material remains mean physical evidence of human habitation, occupation, use, or activity, including the site, location, or context in which
such evidence is situated.

Maximum efficient rate (MER) means the maximum sustainable daily oil or gas withdrawal rate from a reservoir that will permit economic development and depletion of that reservoir without detriment to ultimate recovery.

Maximum production rate (MPR) means the approved maximum daily rate at which oil or gas may be produced from a specified oil-well or gas-well completion.

Minerals include oil, gas, sulphur, geopressured-geothermal and associated resources, and all other minerals that are authorized by an Act of Congress to be produced.

Natural resources include, without limiting the generality thereof, oil, gas, and all other minerals, and fish, shrimp, oysters, clams, crabs, lobsters, sponges, kelp, and other marine animal and plant life but does not include water power or the use of water for the production of

power.

Nonattainment area means, for any air pollutant, an area that is shown by monitored data or that is calculated by air quality modeling (or other methods determined by the Administrator of EPA to be reliable) to exceed any primary or secondary ambient air quality standard established by EPA.

Nonsensitive reservoir means a reservoir in which ultimate recovery is not decreased by high reservoir production rates.

Oil reservoir means a reservoir that contains hydrocarbons predominantly in a liquid (single-phase) state.

Oil reservoir with an associated gas

cap means a reservoir that contains hydrocarbons in both a liquid and gaseous (two-phase) state.

Oil-well completion means a well completed in an oil reservoir or in the
oil accumulation of an oil reservoir with an associated gas cap. Operating rights mean any interest held in a lease with the right to explore for, develop, and produce leased
substances.

Operator means the person the lessee(s) designates as having control or management of operations on the leased area or a portion thereof. An operator may be a lessee, the BSEE-approved or BOEM-approved designated agent of the lessee(s), or the holder of operating rights under a BOEM-approved operating rights assignment.

Outer Continental Shelf (OCS) means all submerged lands lying seaward and
outside of the area of lands beneath navigable waters as defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301) whose subsoil and seabed appertain to the United States and are subject to its jurisdiction and control.

Person includes a natural person, an association (including partnerships, joint ventures, and trusts), a State, a political subdivision of a State, or a private, public, or municipal corporation.

Pipelines are the piping, risers, and appurtenances installed for transporting oil, gas, sulphur, and produced waters.

Processed geological or geophysical information means data collected under a permit or a lease that have been processed or reprocessed. Processing involves changing the form of data to facilitate interpretation. Processing operations may include, but are not limited to, applying corrections for known perturbing causes, rearranging or filtering data, and combining or transforming data elements. Reprocessing is the additional processing other than ordinary processing used in the general course of evaluation. Reprocessing operations may include varying identified parameters for the detailed study of a specific problem area.

Production means those activities that take place after the successful completion of any means for the removal of minerals, including such removal, field operations, transfer of minerals to shore, operation monitoring, maintenance, and workover operations.

Production areas are those areas where flammable petroleum gas, volatile liquids or sulphur are produced, processed ( e.g., compressed), stored, transferred ( e.g., pumped), or otherwise handled before entering the transportation process.

Projected emissions mean emissions, either controlled or uncontrolled, from

a source or sources.

Prospect means a geologic feature having the potential for mineral deposits. Regional Director means the BSEE officer with responsibility and authority for a Region within BSEE.

Regional Supervisor means the BSEE officer with responsibility and authority for operations or other designated program functions within a BSEE Region.

Right-of-use means any authorization
issued under 30 CFR Part 550 to use
OCS lands.

Right-of-way pipelines are those pipelines that are contained within:

(1) The boundaries of a single lease or unit, but are not owned and operated by a lessee or operator of that lease or unit;

(2) The boundaries of contiguous (not cornering) leases that do not have a common lessee or operator;

(3) The boundaries of contiguous (not cornering) leases that have a common lessee or operator but are not owned and operated by that common lessee or
operator; or

(4) An unleased block(s). Routine operations, for the purposes of subpart F, mean any of the following operations conducted on a well with the
tree installed:

(1) Cutting paraffin;(2) Removing and setting 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

**§ 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: (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. **§ 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. **§ 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. **§ 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 30 CFR citation

(1) [Reserved] (2) [Reserved] (3) Suspension of Operations/Suspension of Production (SOO/SOP)

Request. $1,968 ............................................ § 250.171(e).

(4) [Reserved] (5) [Reserved] (6) Deepwater Operations Plan .............................................................. $3,336 .............................. .............. § 250.292(p). (7) [Reserved] (8) Application for Permit to Drill (APD; Form BSEE–0123) .................. $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. (9) Application for Permit to Modify (APM; Form BSEE–0124) .............. $116 ............................................... § 250 .460; § 250.513(b); § 250.613(b); 250.1618(a); § 250.1622; § 250.1704(g). (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. § 250.802(e).

(11) New Facility Production Safety System Application for facility with

25–125 components. $1,218 Additional fee of $8,313 will be charged if BSEE deemsit necessary to visit a facility offshore, and $4,766 to visit a facility in a shipyard. § 250.802(e).

(12) New Facility Production Safety System Application for facility with

fewer than 25 components. $604 ............................................... § 250.802(e).

(13) Production Safety System Application—Modification with more

than 125 components reviewed. $561 ............................................... § 250.802(e).

(14) Production Safety System Application—Modification with 25–125

components reviewed. $201 ............................................... § 250.802(e).

(15) Production Safety System Application—Modification with fewer

than 25 components reviewed. $85 ................................................. § 250.802(e).

(16) Platform Application—Installation—Under the Platform Verification

Program. $21,075 .......................................... § 250.905(l).

(17) Platform Application—Installation—Fixed Structure Under the

Platform Approval Program. $3,018 ............................................ § 250.905(l).

(18) Platform Application—Installation—Caisson/Well Protector ............ $1,536 ............................................ § 250 .905(l) (19) Platform Application—Modification/Repair ...................................... $3,601 ...................................... ...... § 250.905(l). (20) New Pipeline Application (Lease Term) .......................................... $3,283 ..................................... ....... § 250.1000(b). (21) Pipeline Application—Modification (Lease Term) ............................ $1,906 .......................................... .. § 250.1000(b). (22) Pipeline Application—Modification (ROW) ...................................... $3,865 ....................................... ..... § 250.1000(b). (23) Pipeline Repair Notification ............................................................. $360 ............................. .................. § 250.1008(e). (24) Pipeline Right-of-Way (ROW) Grant Application ............................. $2,569 .......................................... .. § 250.1015(a). (25) Pipeline Conversion of Lease Term to ROW .................................. $219 ............................................ ... § 250.1015(a). (26) Pipeline ROW Assignment .............................................................. $186 ................................. .............. § 250.1018(b). (27) 500 Feet From Lease/Unit Line Production Request ...................... $3,608 ............................................ § 2 50.1156(a). (28) Gas Cap Production Request .......................................................... $4,592 ................................ ............ § 250.1157. (29) Downhole Commingling Request .................................................... $5,357 .................................... ........ § 250.1158(a). (30) Complex Surface Commingling and Measurement Application ...... $3,760 ............................................ § 250.1202(a); § 250.1203(b); § 250.1204(a). (31) Simple Surface Commingling and Measurement Application ......... $1,271 ............................................ § 250.1202 (a); § 250.1203(b); § 250.1204(a). (32) Voluntary Unitization Proposal or Unit Expansion .......................... $11,698 ......................................... . § 250.1303(d). (33) Unitization Revision ......................................................................... $831 ......................... ...................... § 250.1303(d). (34) Application to Remove a Platform or Other Facility ........................ $4,342 .......................................... .. § 250.1727. (35) Application to Decommission a Pipeline (Lease Term) .................. $1,059 ............................................ § 250.1751(a) or § 250.1752(a). (36) Application to Decommission a Pipeline (ROW) ............................. $2,012 ............................................ § 250.1751(a) or § 250.1752(a).

(b) Payment of the fees listed in paragraph (a) of this section must accompany the submission of the document for approval or be sent to an office identified by the Regional Director. Once a fee is paid, it is nonrefundable, even if an application or other request is withdrawn. If your application is returned to you as incomplete, you are not required to submit a new fee when you submit the amended application.

(c) Verbal approvals are occasionally given in special circumstances. Any action that will be considered a verbal permit approval requires either a paper permit application to follow the verbal approval or an electronic application submittal within 72 hours. Payment must be made with the completed paper or electronic application.


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**§ 250.126 Electronic payment instructions.**

You must file all payments electronically through Pay.gov. This includes, but is not limited to, all OCS applications or filing fee payments. The Pay.gov Web site may be accessed through a link on the BSEE Offshore
Web site at: http://www.bsee.gov/ offshore/ homepage or directly through Pay.gov at: https://www.pay.gov/ paygov/.

(a) If you submitted an application through eWell, you must use the interactive payment feature in that system, which directs you through Pay.gov.

(b) For applications not submitted electronically through eWell, you must use credit card or automated clearing house (ACH) payments through the Pay.gov Web site, and you must include a copy of the Pay.gov confirmation receipt page with your application.

Inspections of Operations

**§ 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.

**§ 250.133 Will BSEE reimburse me for my expenses related to inspections?** 

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

Disqualification

**§ 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

**§ 250.140 When will I receive an oral approval?** 

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

When you . . . We may . . . And . . .

(a) Request approval orally Give you an oral approval, You must then confirm the oral request by sending us a written request within 72 hours. (b) Request approval in writing, Give you an oral approval if quick action is needed, We will send you a written approval afterward. It will include any conditions that we place on the oral approval. (c) Request approval orally for gas

flaring, Give you an 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).

**§ 250.141 May I ever use alternate procedures or equipment?** 

You may use alternate procedures or equipment after receiving approval as
described in this section.

(a) Any alternate procedures or equipment that you propose to use must provide a level of safety and environmental protection that equals or surpasses current BSEE requirements.

(b) You must receive the District Manager’s or Regional Supervisor’s written approval before you can use alternate procedures or equipment. (c) To receive approval, you must either submit information or give an oral presentation to the appropriate Regional Supervisor. Your presentation must describe the site-specific application(s), performance characteristics, and safety features of the proposed procedure or equipment.

**§ 250.142 How do I receive approval for departures?** 

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

**§ 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)

**§ 250.150 How do I name facilities and wells in the Gulf of Mexico Region?** 

(a) Assign each facility a letter designation except for those types of facilities identified in paragraph (c)(1) of this section. For example, A, B, CA, or

CB.

(1) After a facility is installed, rename each predrilled well that was assigned only a number and was suspended temporarily at the mudline or at the
surface. Use a letter and number designation. The letter used must be the same as that of the production facility, and the number used must correspond
to the order in which the well was completed, not necessarily the number assigned when it was drilled. For example, the first well completed for production on Facility A would be renamed Well A–1, the second would be Well A–2, and so on; and

(2) When you have more than one facility on a block, each facility installed, and not bridge-connected to another facility, must be named using a different letter in sequential order. For example, EC 222A, EC 222B, EC 222C. (3) When you have more than one facility on multiple blocks in a local area being co-developed, each facility
installed and not connected with a walkway to another facility should be named using a different letter in sequential order with the block number corresponding to the block on which the platform is located. For example, EC 221A, EC 222B, and EC 223C.

(b) In naming multiple well caissons, you must assign a letter designation.

(c) In naming single well caissons, you must use certain criteria as follows:

(1) For single well caissons not attached to a facility with a walkway, use the well designation. For example, Well No. 1;

(2) For single well caissons attached to a facility with a walkway, use the same designation as the facility. For example, rename Well No.10 as A–10;
and

(3) For single well caissons with production equipment, use a letter designation for the facility name and a letter plus number designation for the well. For example, the Well No. 1 caisson would be designated as Facility A, and the well would be Well A–1.

**§ 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 What identification signs must I display?** 

(a) You must identify all facilities, artificial islands, and mobile offshore drilling units with a sign maintained in a legible condition.

(1) You must display an identification sign that can be viewed from the
waterline on at least one side of the platform. The sign must use at least 3- inch letters and figures.

(2) When helicopter landing facilities are present, you must display an additional identification sign that is visible from the air. The sign must use at least 12-inch letters and figures and must also display the weight capacity of the helipad unless noted on the top of the helipad. If this sign is visible to both helicopter and boat traffic, then the sign in paragraph (a)(1) of this section is not required.

(3) Your identification sign must: (i) List the name of the lessee or designated operator;

(ii) In the GOM OCS Region, list the area designation or abbreviation and the block number of the facility location as depicted on OCS Official Protraction Diagrams or leasing maps;

(iii) In the Pacific OCS Region, list the lease number on which the facility is located; and

(iv) List the name of the platform, structure, artificial island, or mobile offshore drilling unit.

(b) You must identify singly completed wells and multiple completions as follows:

(1) For each singly completed well,
list the lease number and well number on the wellhead or on a sign affixed to the wellhead;

(2) For wells with multiple completions, downhole splitter wells, and multilateral wells, identify each completion in addition to the well name and lease number individually on the well flowline at the wellhead; and

(3) For subsea wells that flow individually into separate pipelines, affix the required sign on the pipeline
or surface flowline dedicated to that
subsea well at a convenient location on the receiving platform. For multiple
subsea wells that flow into a common pipeline or pipelines, no sign is required.

**§ 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 How long does a suspension**

**last?**

(a) BSEE may issue suspensions for up to 5 years per suspension. The Regional Supervisor will set the length of the suspension based on the
conditions of the individual case involved. BSEE may grant consecutive suspension periods.

(b) An SOO ends automatically when the suspended operation commences.

(c) An SOP ends automatically when production begins.

(d) A Directed Suspension normally ends as specified in the letter directing the suspension.

(e) BSEE may terminate any suspension when the Regional Supervisor determines the circumstances that justified the suspension no longer exist or that other
lease conditions warrant termination. The Regional Supervisor will notify you
of the reasons for termination and the
effective date.

**§ 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.

**§ 250.172 When may the Regional Supervisor grant or direct an SOO or SOP?** 

The Regional Supervisor may grant or direct an SOO or SOP under any of the following circumstances:

(a) When necessary to comply with judicial decrees prohibiting any activities or the permitting of those
activities. The effective date of the suspension will be the effective date required by the action of the court;

(b) When activities pose a threat of serious, irreparable, or immediate harm or damage. This would include a threat to life (including fish and other aquatic life), property, any mineral deposit, or the marine, coastal, or human environment. BSEE may require you to do a site-specific study (see § 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: (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 ofidentifying 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 ofidentifying 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?**

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 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 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.

**§ 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 (H 2 S) 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 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 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


### 64503 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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.

**§ 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 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. **§ 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, When the well goes on production or according to the table in paragraph (b) of this section, whichever is earlier.(2) BSEE–0123S, Supplemental APD Information Sheet, Items 3, 7, 8, 15 and 17, When the well goes on production or according to the table in paragraph (b) of this section, whichever is earlier.(3) BSEE–0124, Application for Permit to Modify, Item 17, When the well goes on production or according to the table in paragraph (b) of this section, whichever is earlier.(4) BSEE–0125, End of Operations Report, Items 12, 13, 17, 21, 22, 26 through 38, 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 periodof time in the table in paragraph (b) has expired. (5) BSEE–0126, Well Potential Test Report, Item 101, 2 years after you submit it. (6) [Reserved] (7) BSEE–0133 Well Activity 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, When the well goes on production or according to the table in paragraph (b) of this section, whichever is earlier.

(8) BSEE–0133S Open Hole Data Report, Boxes 7 and 8, 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, At any time, BSEE will release data and information only if release would further the National interest without unduly damaging the competitive position of the lessee. (2) Data or information is collected

with high-resolution systems ( e.g., bathymetry, side-scan sonar, subbottom profiler, and magnetometer) to comply withsafety or environmental protection requirements, Geophysical data, Geologicaldata, Interpreted G&G information, Processed geological information, Analyzed geological information, 60 days after BSEE receives thedata or information, if the Regional Supervisor deems it necessary, BSEE will release the data and information earlier than 60 daysif 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 yousatisfy him/her that it would unduly damage your competitive position.(3) Your lease is no longer in effect, Geophysical data, Geologicaldata, Processed G&G information Interpreted G&G information, Analyzed geological information, When your lease terminates, This release time applies only ifthe 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 geophysicaldata and information only if acquired postlease for a lessee’s

exclusive use.


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If . . . BSEE will release . . . At this time . . . Special provisions . . .

(4) Your lease is still in effect, Geophysical data, Processedgeophysical information, Interpreted G&G information, 10 years after you submit the data and information, This release time applies only ifthe provisions in this table governing high-resolution systems and the provisions in 30 CFR552.7 do not apply. This release time applies to the geophysical data and information only if acquired postlease for a

lessee’s exclusive use. (5) Your lease is still in effect 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, These release times apply only ifthe provisions in this table governing high-resolution systems and the provisions in 30 CFR552.7 do not apply. If the primary term specified in the lease is extended under the headingof ‘‘Suspensions’’ in this subpart, the extension applies to this provision.(6) Your lease is in effect and beyond the primary term specified in the lease, Geological data, Analyzed geological information, 2 years after the required submittal date, None.

(7) Data or information is submitted on well operations, Descriptions of downhole locations, operations, and equipment, When the well goes on productionor when geological data is released according to §§ 250.197(b)(5) and (b)(6), whichever occurs earlier, Directional survey data may be

released earlier to the owner of an adjacent lease according to Subpart D of this part.

(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, Any data or information obtained, At any time, None.

(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, G&G data, analyzed geological information, processed and interpreted G&G information, Geological data and information: 10 years after BOEM issues the permit; Geophysical data: 50 years after BOEM issues thepermit; Geophysical information: 25 years after BOEM issues the permit, None.

(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) identify the publishing organization of the documents, the address and phone number where you may obtain these documents, and the documents incorporated by reference. The Director of the Federal Register has approved the incorporations by reference according to 5 U.S.C. 552(a) and 1 CFR part 51.

(1) Incorporation by reference of a

document is limited to the edition of the publication that is cited in this section.

Future amendments or revisions of the

document are not included. The BSEE will publish any changes to a document

in the Federal Register and amend this

section.

(2) The BSEE may make the rule amending the document effective without prior opportunity for public

comment when BSEE determines:

(i) That the revisions to a document result in safety improvements or represent new industry standard technology and do not impose undue costs on the affected parties; and (ii) The BSEE meets the requirements for making a rule immediately effective
under 5 U.S.C. 553.

(3) The effect of incorporation by
reference of a document into the regulations in this part is that the incorporated document is a requirement. When a section in this part incorporates all of a document, you are responsible for complying with the provisions of that entire document, except to the extent that section provides otherwise. When a section in this part incorporates part of a document, you are responsible for complying with that part of the document as provided in that section. If any incorporated document uses the
word should, it means must for purposes of these regulations.

(b) The BSEE incorporated each document or specific portion by
reference in the sections noted. The entire document is incorporated by reference, unless the text of the corresponding sections in this part calls for compliance with specific portions of


### 64506 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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: http://www.archives.gov/ federal

_register/
code

_of

_ federal

_regulations/
ibr

_locations.htm. (e) American Concrete Institute (ACI), ACI Standards, P. O. Box 9094, Farmington Hill, MI 48333–9094: http://
www.concrete.org; phone: 248–848–

3700:

(1) ACI Standard 318–95, Building Code Requirements for Reinforced Concrete (ACI 318–95), incorporated by reference at § 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; http:// 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; http://www.ansi.org; phone: 212–642– 4900; and/or American Society of Mechanical Engineers (ASME), 22 Law Drive, P.O. Box 2900, Fairfield, NJ

07007–2900; http://www.asme.org; phone: 973–882–5155: (1) ANSI/ASME Boiler and Pressure Vessel Code, Section I, Rules for Construction of Power Boilers; including Appendices, 2004 Edition; and July 1, 2005 Addenda, and all Section I Interpretations Volume 55, incorporated by reference at § 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; http:// www.api.org; phone: 202–682–8000:

(1) API 510, Pressure Vessel Inspection Code: In-Service Inspection, Rating, Repair, and Alteration, Downstream Segment, Ninth Edition, June 2006; incorporated by reference at §§ 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; (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;


### 64507 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

(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; 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; 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;


### 64508 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

(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 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; (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,


### 64509 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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; http://www.astm.org; phone: 610–832–

9500: (1) ASTM Standard C 33–07, approved December 15, 2007, Standard Specification for Concrete Aggregates; incorporated by reference at § 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; http://www.aws.org; phone: 800–443–9353:

(1) AWS D1.1:2000, Structural Welding Code—Steel, 17th Edition, October 18, 1999; incorporated by reference at § 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; http://www.nace.org; phone:

281–228–6200:

(1) NACE Standard MR0175–2003, Standard Material Requirements, Metals for Sulfide Stress Cracking and Stress Corrosion Cracking Resistance in Sour Oilfield Environments, Revised January 17, 2003; incorporated by reference at §§ 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. **§ 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:

30 CFR subpart, title and/or BSEE Form (OMB Control No.) 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. To inform BSEE of actions taken to comply with general operational requirements on the OCS. To ensure that operations on the OCS meetstatutory 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 reserveestimation, 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.


### 64510 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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, andcoastal environment, and will result in diligent exploration, development, and production of leases. (3) Subpart C, Pollution Prevention and Control (1010–0057) ................ To inform BSEE of measures to be taken to prevent water pollution. Toensure that appropriate measures are taken to prevent water pollution.(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. 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.

(5) Subpart E, Oil and Gas Well-Completion Operations (1010–0067) .. To inform BSEE of the equipment and procedures to be used in wellcompletion operations on the OCS. To ensure that well-completionoperations are safe and protect the human, marine, and coastal environment. (6) Subpart F, Oil and Gas Well Workover Operations (1010–0043) ..... To inform BSEE of the equipment and procedures to be used d uring well-workover operations on the OCS. To ensure that well-workoveroperations are safe and protect the human, marine, and coastal environment. (7) Subpart H, Oil and Gas Production Safety Systems (1010–0059) .... To inform BSEE of the equipment and procedures to be used d uringproduction operations on the OCS. To ensure that production operations are safe and protect the human, marine, and coastal environment. (8) Subpart I, Platforms and Structures (1010–0149) .............................. To provide BSEE with information regarding thedesign, fabrication,and installation of platforms on the OCS. To ensure the structural integrity of platforms installed on the OCS.(9) Subpart J, Pipelines and Pipeline Rights-of-Way (1010–0050), including Form BSEE–0149, Assignment of Federal OCS Pipeline Right-of-Way Grant. 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. (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. To inform BSEE of production rates for hydrocarbons produced on theOCS. To ensure economic maximization of ultimate hydrocarbon recovery(11) Subpart L, Oil and Gas Production Measurement, Surface Commingling, and Security (1010–0051). 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. (12) Subpart M, Unitization (1010–0068) ................................................. To inform BSEE of the unitization of leases. To ensure that unitizationprevents waste, conserves natural resources, and protects correlative rights.(13) Subpart N, Remedies and Penalties ................................................ The requirements in subpart N are exempt from the Paperwork Reduction Act of 1995 according to 5 CFR 1320.4. (14) Subpart O, Well Control and Production Safety Training (1010–

0128). To inform BSEE of training program curricula, course schedules, andattendance. To ensure that training programs are technically accurate and sufficient to meet safety and environmental requirements, and that workers are properly trained to operate on the OCS. (15) Subpart P, Sulphur Operations (1010–0086) ................................... To inform BSEE of sulphur exploration and development operations on the OCS. To ensure that OCS sulphur operations are safe; protectthe human, marine, and coastal environment; and will result in diligent exploration, development, and production of sulphur leases. (16) Subpart Q, Decommissioning Activities (1010–0142) ...................... To determine that decommissioning activities complywith regulatoryrequirements and approvals. To ensure that site clearance and platform or pipeline removal are properly performed to protect marine life

and the environment and do not conflict with other users of the OCS. (17) Subpart S, Safety and Environmental Management Systems

(1010–0186), including Form BSEE–0131, Performance Measures

Data. The SEMS program will describe management commitment to safety and the environment, as well as policies and procedures to assuresafety 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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**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 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.

You must submit a(n) . . . Before you . . .

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

(b) Submitting additional information. On a case-by-case basis, the Regional Supervisor may require you to submit additional information if the Regional Supervisor determines that it is necessary to evaluate your proposed plan or document.

(c) Limiting information. The Regional Director may limit the amount of information or analyses that you otherwise must provide in your proposed plan or document under this subpart when:

(1) Sufficient applicable information or analysis is readily available to BSEE;

(2) Other coastal or marine resources are not present or affected;

(3) Other factors such as technological advances affect information needs; or

(4) Information is not necessary or required for a State to determine consistency with their CZMA Plan.

(d) Referencing. In preparing your proposed plan or document, you may reference information and data discussed in other plans or documents you previously submitted or that are otherwise readily available to BSEE.

**§ 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 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 post approval monitoring?** 

The Regional Supervisor may direct you to conduct monitoring programs. You must retain copies of all monitoring data obtained or derived from your monitoring programs and make them available to BSEE upon request. The Regional Supervisor may require you to:

(a) Monitoring plans. Submit monitoring plans for approval before you begin work; and

(b) Monitoring reports. Prepare and submit reports that summarize and analyze data and information obtained or derived from your monitoring programs. The Regional Supervisor will specify requirements for preparing and submitting these reports.

Deepwater Operations Plan (DWOP)

**§ 250.286 What is a DWOP?**

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

(b) The DWOP process consists of two parts: a Conceptual Plan and the DWOP. Section 250.289 prescribes what the Conceptual Plan must contain, and § 250.292 prescribes what the DWOP

must contain.

**§ 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 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 What must the Conceptual Plan**

**contain?**

In the Conceptual Plan, you must explain the general design basis and philosophy that you will use to develop
the field. You must include the following information:

(a) An overview of the development concept(s);

(b) A well location plat; (c) The system control type (i.e., direct hydraulic or electro-hydraulic);
and

(d) The distance from each of the wells to the host platform.

**§ 250.290 What operations require approval of the Conceptual Plan?** 

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

**§ 250.291 When and how must I submit the**
**DWOP?**

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

**§ 250.292 What must the DWOP contain?**

You must include the following information in your DWOP:

(a) A description and schematic of the typical wellbore, casing, and completion;

(b) Structural design, fabrication, and
installation information for each surface system, including host facilities;

(c) Design, fabrication, and installation information on the mooring systems for each surface system;

(d) Information on any active stationkeeping system(s) involving thrusters or other means of propulsion used with a surface system;

(e) Information concerning the drilling and completion systems;

(f) Design and fabrication information for each riser system ( e.g., drilling, workover, production, and injection);

(g) Pipeline information; (h) Information about the design, fabrication, and operation of an offtake system for transferring produced hydrocarbons to a transport vessel;

(i) Information about subsea wells and associated systems that constitute all or part of a single project development covered by the DWOP;

(j) Flow schematics and Safety Analysis Function Evaluation (SAFE) charts (API RP 14C, subsection 4.3c, incorporated by reference in § 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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the lessee shall take measures to prevent unauthorized discharge of pollutants
into the offshore waters. The lessee shall not create conditions that will pose unreasonable risk to public health, life, property, aquatic life, wildlife, recreation, navigation, commercial fishing, or other uses of the ocean.

(1) When pollution occurs as a result of operations conducted by or on behalf of the lessee and the pollution damages or threatens to damage life (including fish and other aquatic life), property, any mineral deposits (in areas leased or not leased), or the marine, coastal, or human environment, the control and removal of the pollution to the satisfaction of the District Manager shall be at the expense of the lessee.
Immediate corrective action shall be taken in all cases where pollution has
occurred. Corrective action shall be subject to modification when directed by the District Manager.

(2) If the lessee fails to control and remove the pollution, the Director, in cooperation with other appropriate Agencies of Federal, State, and local governments, or in cooperation with the lessee, or both, shall have the right to control and remove the pollution at the lessee’s expense. Such action shall not relieve the lessee of any responsibility provided for by law.

(b)(1) The District Manager may restrict the rate of drilling fluid discharges or prescribe alternative discharge methods. The District Manager may also restrict the use of components which could cause unreasonable degradation to the marine environment. No petroleum-based substances, including diesel fuel, may be added to the drilling mud system without prior approval of the District Manager.

(2) Approval of the method of disposal of drill cuttings, sand, and
other well solids shall be obtained from the District Manager.

(3) All hydrocarbon-handling equipment for testing and production such as separators, tanks, and treaters shall be designed, installed, and operated to prevent pollution. Maintenance or repairs which are necessary to prevent pollution of
offshore waters shall be undertaken immediately.

(4) Curbs, gutters, drip pans, and
drains shall be installed in deck areas in a manner necessary to collect all
contaminants not authorized for discharge. Oil drainage shall be piped to a properly designed, operated, and maintained sump system which will automatically maintain the oil at a level sufficient to prevent discharge of oil into offshore waters. All gravity drains shall be equipped with a water trap or other means to prevent gas in the sump system from escaping through the drains. Sump piles shall not be used as processing devices to treat or skim liquids but may be used to collecttreated-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. **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 When and how must I secure a**

**well?**

Whenever you interrupt drilling operations, you must install a downhole safety device, such as a cement plug, bridge plug, or packer. You must install the device at an appropriate depth within a properly cemented casing string or liner.

(a) Among the events that may cause you to interrupt drilling operations are:

(1) Evacuation of the drilling crew; (2) Inability to keep the drilling rig on location; or

(3) Repair to major drilling or 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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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.

**§ 250.404 What are the requirements for**

**the crown block?**

You must have a crown block safety device that prevents the traveling block from striking the crown block. You must check the device for proper operation atleast once per week and after each drillline slipping operation and record the results of this operational check in the driller’s report.

**§ 250.405 What are the safety requirements for diesel engines used on a**  **drilling rig?**

You must equip each diesel engine
with an air take device to shut down the diesel engine in the event of a runaway.

(a) For a diesel engine that is not continuously manned, you must equip the engine with an automatic shutdown device;

(b) For a diesel engine that is continuously manned, you may equip the engine with either an automatic or
remote manual air intake shutdown device;

(c) You do not have to equip a diesel engine with an air intake device if it meets one of the following criteria:

(1) Starts a larger engine; (2) Powers a firewater pump; (3) Powers an emergency generator; (4) Powers a BOP accumulator system; (5) Provides air supply to divers or confined entry personnel;

(6) Powers temporary equipment on a nonproducing platform;

(7) Powers an escape capsule; or (8) Powers a portable single-cylinder rig washer.

**§ 250.406 What additional safety measures must I take when I conduct drilling**  **operations on a platform that has producing wells or has other hydrocarbon flow?** 

You must take the following safety measures when you conduct drilling operations on a platform with producing wells or that has other hydrocarbon
flow:

(a) You must install an emergency
shutdown station near the driller’s console;

(b) You must shut in all producible wells located in the affected wellbay
below the surface and at the wellhead
when:

(1) You move a drilling rig or related equipment on and off a platform. This includes rigging up and rigging down
activities within 500 feet of the affected platform;

(2) You move or skid a drilling unit between wells on a platform;

(3) A mobile offshore drilling unit (MODU) moves within 500 feet of a platform. You may resume production once the MODU is in place, secured, and ready to begin drilling operations.

**§ 250.407 What tests must I conduct to**

**determine reservoir characteristics?**

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

**§ 250.408 May I use alternative procedures or equipment during drilling operations?** 

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

**§ 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 How do I obtain approval to drill**

**a well?**

You must obtain written approval from the District Manager before you begin drilling any well or before you sidetrack, bypass, or deepen a well. To obtain approval, you must:

(a) Submit the information required by §§ 250.411 through 250.418;

(b) Include the well in your approved Exploration Plan (EP), Development and Production Plan (DPP), or Development Operations Coordination Document (DOCD);

(c) Meet the oil spill financial responsibility requirements for offshore facilities as required by 30 CFR part 553;
and

(d) Submit the following to the District Manager:

(1) An original and two complete copies of Form BSEE–0123, Application for Permit to Drill (APD), and Form BSEE–0123S, Supplemental APD Information Sheet;

(2) A separate public information copy of forms BSEE–0123 and BSEE– 0123S that meets the requirements of § 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 Where to find a description

(a) Plat that shows locations

of the proposed well. § 250.412

(b) Design criteria used for the

proposed well. § 250.413

(c) Drilling prognosis ............... § 250.414(d) Casing and cementing programs. § 250.415

(e) Diverter and BOP systems

descriptions. § 250.416

(f) Requirements for using an

MODU. § 250.417

(g) Additional information ........ § 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.

**§ 250.414 What must my drilling prognosis**

**include?**

Your drilling prognosis must include a brief description of the procedures you will follow in drilling the well. This prognosis includes but is not limited to the following:

(a) Projected plans for coring at specified depths;

(b) Projected plans for logging; (c) Planned safe drilling margin between proposed drilling fluid weights and estimated pore pressures. This safe drilling margin may be shown on the plot required by § 250.413(g);

(d) Estimated depths to the top of significant marker formations;

(e) Estimated depths to significant porous and permeable zones containing fresh water, oil, gas, or abnormally pressured formation fluids;

(f) Estimated depths to major faults; (g) Estimated depths of permafrost, if applicable;

(h) A list and description of all requests for using alternative procedures or departures from the requirements of this subpart in one place in the APD. You must explain how the alternative procedures afford an equal or greater degree of protection, safety, or performance, or why you need the departures; and

(i) Projected plans for well testing (refer to § 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; (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 atechnical 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.

**§ 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, 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. 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, 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. If you drilled a portion of this hole, you must use enough cement to fill the annular space back to the

mudline.(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 theplanned casing point, you must set casing immediately. 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 ........................... 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. 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.(d) Intermediate .................... Design casing and select setting depth based on anticipated or encountered geologic characteristics or

wellbore conditions. 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.(e) Production ...................... Design casing and select setting depth based on anticipated or encountered geologic characteristics or

wellbore conditions. 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. (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. Same as cementing requirements for specific casingtypes. For example, a liner used as intermediate casing must be cemented according to the cementing requirements for intermediate casing.

**§ 250.422 When may I resume drilling after cementing?** 

(a) After cementing surface, intermediate, or production casing (or liners), you may resume drilling after

the cement has been held under pressure for 12 hours. For conductor casing, you may resume drilling after

the cement has been held under pressure for 8 hours. One acceptable method of holding cement under pressure is to use float valves to hold the cement in place. (b) If you plan to nipple down your diverter or BOP stack during the 8- or 12-hour waiting time, you must determine, before nippling down, when

it will be safe to do so. You must base your determination on a knowledge of formation conditions, cement composition, effects of nippling down, presence of potential drilling hazards, well conditions during drilling, cementing, and post cementing, as well as past experience. **§ 250.423 What are the requirements for pressure testing casing?** 

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

Casing type Minimum test pressure

(1) Drive or Structural ............................................................................... Not required. (2) Conductor ............................................................................................ 200 psi. (3) Surface, Intermediate, and Production ............................................... 70 percent of its minimum internal yiel d.

(b) You must ensure proper installation of casing or liner in the subsea wellhead or liner hanger. (1) You must ensure that the latching

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


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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 anotherindication 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, Submit a revised casing program to the District Manager for approval.

(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, Submit those changes to the District Manager for approval.

(c) Have indication of inadequate cement job (such as lost returns, cement channeling, or failure of equipment), (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. (d) Inadequate cement job, Re-cement or take other remedial actions as approved by the District Manager. (e) Primary cement job that did not isolate abnormal pressure intervals, Isolate those intervals from normal pressures by squee ze cementing before you complete; suspend operations; or abandon the well,

whichever occurs first. (f) Decide to produce a well that was not originally contemplated for

production, 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. (g) Want to drill a well without setting conductor casing, Submit geologic data and information to the District Manager that de monstrates the absence of shallow hydrocarbons or hazards. This information must include logging and drilling fluid-monitoring from wells previously drilled within 500 feet of the proposed well path down to the next casing point.(h) Need to use less than required cement for the surface casing during floating drilling operations to provide protection from burst and collapse pressures, Submit information to the District Manager that demonstrates the use of less cement is necessary.

(i) Cement across a permafrost zone, 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 When must I install a diverter system?** 

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

**§ 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, Use flexible hose that has integral end couplings. (b) Use only one spool outlet for your diverter system, (1) Have branch lines that meet the minimum internal diameter requirements; and (2) Provide downwind diversion capability. (c) Use a spool with an outlet with an internal diameter of less than 10

inches on a surface wellhead, Use a spool that has dual outlets with an internal diameter of at least 8

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

**§ 250.433 What are the diverter actuation and testing requirements?** 

When you install the diverter system, you must actuate the diverter sealingelement, 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 upon 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 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. **§ 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


### 64520 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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 withpipe 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. 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 forDrilling Wells (as incorporated by reference in § 250.198). The District Manager may approve a suitable alternate method. (d) Have a subsea BOP stack equipped with remotely operated vehicle

(ROV) intervention capability. 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. (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 ensurethat it is properly maintained and capable of shutting in the well during emergency operations. 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.

(f) Provide autoshear and deadman systems for dynamically positioned

rigs. (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 LMRPcloses the shear rams. This is considered a ‘‘rapid discharge’’ system. (2) Deadman System means a safety system that is designed to automatically close the wellbore in the event of a simultaneous absence of hydraulic supply and signal transmission capacity in both subsea control pods. This is considered a ‘‘rapid discharge’’ system. (3) You may also have an acoustic system. (g) Have operational or physical barrier(s) on BOP control panels to

prevent accidental disconnect functions. Incorporate enable buttons on control panels to ensure two-handed operation for all critical functions. (h) Clearly label all control panels for the subsea BOP system .............. Label other BOP control panels such as hydraulic control panel.(i) Develop and use a management system for operating the BOP system, including the prevention of accidental or unplanned disconnects of the system. The management system must include written procedures for operating the BOP stack and LMRP (including proper techniques to preventaccidental disconnection of these components) and minimum knowledge requirements for personnel authorized to operate and maintain BOP components. (j) Establish minimum requirements for personnel authorized to operate

critical BOP equipment. 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. (k) Before removing the marine riser, displace the fluid in the riser with

seawater. 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. (l) Install the BOP stack in a glory hole when in ice-scour area ............. Your glory hole must be deep enough to ensure thatthe top of the stack is below the deepest probable ice-scour depth.

**§ 250.443 What associated systems and related equipment must all BOP systems** 

**include?**

All BOP systems must include the following associated systems and related equipment:

(a) An automatic backup to the primary accumulator-charging system. The power source must be independent from the power source for the primary accumulator-charging system. The independent power source must possess sufficient capability to close and hold closed all BOP components.

(b) At least two BOP control stations. One station must be on the drilling

floor. You must locate the other station in a readily accessible location away from the drilling floor.

(c) Side outlets on the BOP stack for separate kill and choke lines. If your stack does not have side outlets, you must install a drilling spool with side

outlets. (d) A choke and a kill line on the BOP stack. You must equip each line with two full-opening valves, one of which
must be remote-controlled. For a subsea BOP system, both valves in each line
must be remote-controlled. In addition:

(1) You must install the choke line above the bottom ram;

(2) You may install the kill line below the bottom ram; and

(3) For a surface BOP system, on the kill line you may install a check valve
and a manual valve instead of the


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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.

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

You must use or provide the following BOP equipment during drilling operations:

(a) A kelly valve installed below the swivel (upper kelly valve);

(b) A kelly valve installed at the bottom of the kelly (lower kelly valve). You must be able to strip the lower kelly valve through the BOP stack;

(c) If you drill with a mud motor and use drill pipe instead of a kelly, you must install one kelly valve above, and one strippable kelly valve below, the joint of drill pipe used in place of a kelly;

(d) On a top-drive system equipped with a remote-controlled valve, you must install a strippable kelly-type
valve below the remote-controlled valve;

(e) An inside BOP in the open position located on the rig floor. You
must be able to install an inside BOP for each size connection in the drill string;

(f) A drill-string safety valve in the open position located on the rig floor. You must have a drill-string safety valve
available for each size connection in the drill string;

(g) When running casing, you must have a safety valve in the open position available on the rig floor to fit the casing string being run in the hole;

(h) All required manual and 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. **§ 250.448 What are the BOP pressure tests requirements?** 

When you pressure test the BOPsystem, 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 thedisconnection 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, Correct the problem and retest the affected equipment. (b) Need to repair or replace a surface or subsea BOP system, 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). (c) Need to postpone a BOP test due to well-control problems such as

lost circulation, formation fluid influx, or stuck drill pipe, 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. (d) BOP control station or pod that does not function properly, Suspend further drilling operations until that station or pod is operable. (e) Want to drill with a tapered drill-string, 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. (f) Install casing rams in a BOP stack, Test the ram bonnets before running casing. (g) Want to use an annular BOP with a rated working pressure less

than the anticipated surface pressure, 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. (h) Use a subsea BOP system in an ice-scour area, 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. (i) You activate blind-shear rams or casing shear rams during a well

control situation, in which pipe or casing is sheared, Retrieve, physically inspect, and conduct a full pressure test of the BOP stack after the situation is fully controlled.

Drilling Fluid Requirements

**§ 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: (a) Before starting out of the hole with drill pipe, you must properly condition the drilling fluid. You must circulate a volume of drilling fluid equal to the annular volume with the drill pipe just off-bottom. You may omit this practice if documentation in the driller’s report
shows:

(1) No indication of formation fluid influx before starting to pull the drill pipe from the hole;

(2) The weight of returning drilling fluid is within 0.2 pounds per gallon (1.5 pounds per cubic foot) of the drilling fluid entering the hole; and (3) Other drilling fluid properties are within the limits established by the program approved in the APD.

(b) Record each time you circulate drilling fluid in the hole in the driller’s
report;

(c) When coming out of the hole with drill pipe, you must fill the annulus with drilling fluid before the hydrostatic pressure decreases by 75 psi, or every five stands of drill pipe, whichever gives a lower decrease in hydrostatic pressure. You must calculate the number of stands of drill pipe and drill collars that you may pull before you


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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, 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. (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 ventilationsystem 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 Who establishes field drilling**

**rules?**

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

(b) You may request the District Manager to establish, amend, or cancel field drilling rules.

Applying for a Permit To Modify and
Well Records

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

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

When you . . . Then you must . . . And . . .

(1) Intend to revise your drilling

plan, change major drilling equipment, or plugback, Submit form BSEE–0124 or request oral approval, Receive written or oral approval from the District Manager before youbegin the intended operation. If you get an approval, you must submit form BSEE–0124 no later than the end of the 3rd business dayfollowing the oral approval. In all cases, or you must meet the additional requirements in paragraph (b) of this section. (2) Determine a well’s final surface

location, water depth, and the rotary kelly bushing elevation, Immediately Submit a form BSEE–
0124, Submit a plat certified by a registered land surveyor that meets the requirements of § 250.412.

(3) Move a drilling unit from a

wellbore before completing a well, Submit forms BSEE–0124 and BSEE–0125 within 30 days afterthe suspension of wellbore operations, 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; (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, Ninety days after you complete drilling operations. (b) Casing and liner pressure tests, diverter tests, and BOP tests, Two years after the completion of drilling operations.(c) Completion of a well or of any workover activity that materially alters the completion configuration or affects a hydrocarbon-bearing

zone, 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.

**§ 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 (d) Other reports and records of operations.

Hydrogen Sulfide

**§ 250.490 Hydrogen sulfide.**

(a) What precautions must I take when operating in an H 2 S area? You

must:

(1) Take all necessary and feasible precautions and measures to protect personnel from the toxic effects of H 2 S and to mitigate damage to property and the environment caused by H 2 S. You must follow the requirements of thissection when conducting drilling, wellcompletion/well-workover, and production operations in zones with

H 2 S present and when conducting operations in zones where the presence
of H 2 S is unknown. You do not need to follow these requirements when operating in zones where the absence of

H 2 S 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.

H

2 S absent means: (1) Drilling, logging, coring, testing, or producing operations have confirmed
the absence of H 2 S in concentrations that could potentially result in atmospheric concentrations of 20 ppm
or more of H2 S; or (2) Drilling in the surrounding areas and correlation of geological and seismic data with equivalent stratigraphic units have confirmed an
absence of H 2 S throughout the area to be
drilled.

H

2 S present means that drilling, logging, coring, testing, or producing operations have confirmed the presence
of H 2 S in concentrations and volumes that could potentially result in atmospheric concentrations of 20 ppm
or more of H 2 S.

H

2 S unknown means the designation of a zone or geologic formation where neither the presence nor absence of H2 S
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 H 2 S. You must: (1) Request and obtain an approved
classification for the area from the Regional Supervisor before you begin operations. Classifications are ‘‘H2 S absent,’’ H 2 S present,’’ or ‘‘H 2 S 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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(d) What do I do if conditions change? If you encounter H 2 S that could potentially result in atmospheric concentrations of 20 ppm or more in areas not previously classified as having

H2 S present, you must immediately notify BSEE and begin to follow requirements for areas with H2 S present.

(e) What are the requirements for conducting simultaneous operations? When conducting any combination ofdrilling, 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

H

2 S Contingency Plan. Before you begin operations, you must submit an H2 S 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 H2 S 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 H2 S alert. You must have at least two briefing areas on each facility and use the briefing area that is upwind of the H 2 S 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 H2 S alerts, describe the types of H 2 S emergencies during which you consider the risk of helicopter activity to be acceptable and the precautions you will take during the flights;

(8) Procedures you will use to safely position all vessels attendant to the facility. Indicate where you will locate the vessels with respect to wind
direction. Include the distance from the facility and what procedures you will use to safely relocate the vessels in an

emergency;

(9) How you will provide protectivebreathing equipment for all personnel, including contractors and visitors;

(10) The agencies and facilities you will notify in case of a release of H2 S (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

H 2 S;

(11) The medical personnel and facilities you will use if needed, their addresses, and telephone numbers;

(12) H 2 S detector locations in production facilities producing gas containing 20 ppm or more of H2 S.
Include an ‘‘H 2 S Detector Location Drawing’’ showing:

(i) All vessels, flare outlets, wellheads, and other equipment handling production containing H2 S;

(ii) Approximate maximum
concentration of H2 S in the gas stream;
and

(iii) Location of all H 2 S sensors included in your contingency plan;

(13) Operational conditions when you expect to flare gas containing H 2 S including the estimated maximum gas flow rate, H2 S 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 (SO 2)-detection system(s) you will use
to determine SO 2 concentration and exposure hazard when H2 S is burned;

(18) Increased monitoring and warning procedures you will take when
the SO 2 concentration in the atmosphere reaches 2 ppm;

(19) Personnel protection measures or evacuation procedures you will initiate
when the SO 2 concentration in the atmosphere reaches 5 ppm;

(20) Engineering controls to protect personnel from SO 2 ; and

(21) Any special equipment, procedures, or precautions you will use if you conduct any combination ofdrilling, 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 H 2 S 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

H 2 S 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 H 2 S and SO 2 ; and

(B) Instructions on their responsibilities in the event of an H 2 S
release.

(4) What training must I provide to all other employees? You must train all individuals on your facility on the:

(i) Hazards of H 2 S and of SO 2 and the provisions for personnel safety
contained in the H2 S Contingency Plan;

(ii) Proper use of safety equipment which the employee may be required to

use;

(iii) Location of protective breathing equipment, H2 S 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 H2 S exposure. During all drills and training sessions, you must address procedures for rescue
and first aid for H 2 S victims;

(vi) Location of: (A) The first-aid kit on the facility; (B) Resuscitators; and


### 64527 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

(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 H 2 S 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 H 2 S considerations at the facility, and other updated H 2 S 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 H 2 S and on facilities that process gas containing H 2 S 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 H2 S reaches 20 ppm.

(3) What are the requirements for signs? Each sign must be a highvisibility yellow color with black lettering as follows:

Letter height Wording

12 inches ................... Danger.
Poisonous Gas. Hydrogen Sulfide. 7 inches ..................... Do not approach if red flag is flying. (Use appropriate

wording at right). Do not approach ifred lights are flashing.

(4) May I use existing signs? You may use existing signs containing the words ‘‘Danger-Hydrogen Sulfide-H2 S,’’ 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 H2 S.

(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) H 2 S-detection and H 2 S monitoring equipment: (1) What are the requirements for an H 2 S detection system? An H 2 S detection system must:

(i) Be capable of sensing a minimum of 10 ppm of H 2 S in the atmosphere;
and

(ii) Activate audible and visual alarms
when the concentration of H 2 S in the atmosphere reaches 20 ppm.

(2) Where must I have sensors fordrilling, 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 H 2 S 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 H2 S.

(4) How often must I observe the

sensors? During drilling, wellcompletion and well-workover operations, you must continuously
observe the H 2 S 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 H 2 S 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 H2 S 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 H2 S 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

H 2 S 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

H

2 S Detectors? (i) Personnel trained to calibrate the particular H2 S detector equipment being used must test detectors by exposing them to a known concentration in the range of 10 to 30 ppm of H 2 S.

(ii) If the results of any functional test are not within 2 ppm or 10 percent, whichever is greater, of the applied


### 64528 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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 H 2 S present or H 2 S 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 H2 S

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 H 2 S-detection and H 2 S-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

H 2 S present or H 2 S unknown, you must equip vessels with an H2 S-detection system that activates audible and visual
alarms when the concentration of H 2 S 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 H2 S Contingency Plan.

(10) What are the requirements for nearby facilities? The District Manager may require you to equip nearby facilities with portable or fixed H 2 S 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 H 2 S concentration levels could be exceeded at nearby facilities.

(11) What must I do to protect against

SO 2 if I burn gas containing H 2 S? You

must:

(i) Monitor the SO 2concentration in the air with portable or strategically placed fixed devices capable of detecting a minimum of 2 ppm of SO 2 ; (ii) Take readings at least hourly and at any time personnel detect SO 2 odor or nasal irritation;

(iii) Implement the personnel protective measures specified in the H 2 S Contingency Plan if the SO 2 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 SO 2

.

(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 H 2 S present or H 2 S 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 tofacilities 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 H 2 S alerts, limit helicopter flights to and from facilities to the conditions specified in the H 2 S 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 particularoperation(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 apparatus bottles. The cascade air-bottlesystem 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 H 2 S detectors capable of detecting a 10 ppm concentration of H 2 S 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 therig 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 H 2 S or SO 2 may accumulate; and

(iii) Provide movable ventilation
devices in work areas. The movable
ventilation devices must be multidirectional and capable of dispersing H 2 S or SO 2 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 H 2 S release? You must notify BSEE without delay in the event of a gas release which results in a 15- minute time-weighted average atmospheric concentration of H2 S 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


### 64529 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

procedures? When working in an area
classified as H 2 S present or H 2 S
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

H 2 S, you must immediately conduct
either the Garrett-Gas-Train test or a comparable test for soluble sulfides to confirm the presence of H 2 S.

(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 H 2 S, well-control fluid pH, and corrosion equipment.

(i) Scavengers. You must have scavengers for control of H 2 S available on the facility. When H 2 S 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 addadditives 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 H 2 S 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 H 2 S and other gases must be throughpressurized or atmospheric mudseparator equipment depending on volume, pressure and concentration of

H 2 S. The equipment must be designed
to recover well-control fluids and burn the gases separated from the wellcontrol fluid. The well-control fluid
must be treated to neutralize H2 S and restore and maintain the proper quality.

(o) Well testing in a zone known to

contain H 2 S. When testing a well in a
zone with H2 S 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 H 2 S 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 H2 S 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

H2 S, you must activate SO 2 monitoring equipment in accordance with paragraph (j)(11) of this section. If you
detect SO 2 in excess of 2 ppm, you must implement the personnel protective measures in your H 2 S 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 H2 S

service.

(5) Use tubulars suitable for H 2 S 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 H2 S 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 H2 S

service.

(p) Metallurgical properties of equipment. When operating in a zone
with H 2 S 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 H2 S embrittlement), chloride-stress cracking, hydrogen-induced cracking,
and other failure modes. You must do all of the following:

(1) Use tubulars and other equipment, casing, tubing, drill pipe, couplings, flanges, and related equipment that is designed for H 2 S service.

(2) Use BOP system components, wellhead, pressure-control equipment, and related equipment exposed to H 2 Sbearing 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 H2 S service.

(4) When producing in zones bearing

H 2 S, 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 H 2 S zone: (1) Coring operations. When you conduct coring operations in H2 S-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 H 2 S.

(2) Logging operations. You must treat
and condition well-control fluid in use for logging operations to minimize the
effects of H 2 S on the logging equipment.

(3) Stripping operations. Personnel must monitor displaced well-controlfluid returns and wear protectivebreathing equipment in the working area when the atmospheric
concentration of H 2 S reaches 20 ppm or if the well is under pressure.

(4) Gas-cut well-control fluid or well kick from H 2 S-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


### 64530 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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 H 2 S 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 (H2 S and CO 2) 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 H2 S exists.

(8) Wireline lubricators. Lubricators which may be exposed to fluids containing H 2 S must be of H 2 S-resistant
materials.

(9) Fuel and/or instrument gas. You must not use gas containing H2 S for instrument gas. You must not use gas containing H2 S 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 H2 S-bearing fluids must be
constructed of H 2 S-corrosion resistant
materials or coated so as to resist H 2 S

corrosion.

(11) Elastomer seals. You must use

H 2 S-resistant materials for all seals which may be exposed to fluids containing H 2 S.

(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 H2 S 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 H2 S. The District Manager may require the submittal of an updated analysis if the water disposal rate or the potential H 2 S content increases.

(13) Deck drains. You must equip open deck drains with traps or similar devices to prevent the escape of H2 S 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 H2 S is present. **Subpart E—Oil and Gas Well Completion 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.

**§ 250.501 Definition.**

When used in this subpart, the following term shall have the meaning given below:

Well-completion operations means the
work conducted to establish the production of a well after the production-casing string has been set, cemented, and pressure-tested.

**§ 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 movedshall 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 (H2 S) or in zones where the presence of H 2 S 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, 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 written approval from the District Manager in accordance with § 250.513 of this part. That approval shall be based upon a case-by-case determination that the proposed equipment and procedures will adequately control the well and permit safe production operations.

**§ 250.506 Crew instructions.**

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

**§ 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.


### 64531 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

**§ 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 properoperation 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-completionrules 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 well completion operations.** 

(a) No well-completion operation may begin until the lessee receives written approval from the District Manager. If completion is planned and the data are available at the time you submit the Application for Permit to Drill and Supplemental APD Information Sheet (Forms BSEE–0123 and BSEE–0123S),you may request approval for a 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 producingzone(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 H2 S or a zone where the presence of H 2 S 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 becontinuously 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 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 tofilling 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. (2) The expected pressure is 5,000 psi or greater or you use multiple

tubing strings, Four BOPs consisting of an annular, two sets of pipe rams, and one

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


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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-completionoperations. 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.

**§ 250.516 Blowout preventer system tests, inspections, and maintenance.** 

(a) BOP pressure testing timeframes. You must pressure test your BOP system:

(1) When installed; and (2) Before 14 days have elapsed since your last BOP pressure test. You must begin to test your BOP system before 12 a.m. (midnight) on the 14th day following the conclusion of the previous test. However, the District Manager may require testing every 7 days if conditions or BOP performance warrant.

(b) BOP test pressures. When you test the BOP system, you must conduct a low pressure and a high pressure test for each BOP component. Each individual pressure test must hold pressure long enough to demonstrate that the tested component(s) holds the required pressure. The District Manager may approve or require other test pressures or practices. Required test pressures are
as follows:

(1) All low pressure tests must be between 200 and 300 psi. Any initial pressure above 300 psi must be bled back to a pressure between 200 and 300 psi before starting the test. If the initial pressure exceeds 500 psi, you must
bleed back to zero and reinitiate the test. You must conduct the low pressure test before the high pressure test.

(2) For ram-type BOP’s, choke manifold, and other BOP equipment, the high pressure test must equal the rated working pressure of the equipment.

(3) For annular-type BOP’s, the high pressure test must equal 70 percent of the rated working pressure of the equipment.

(c) Duration of pressure test. Each test must hold the required pressure for 5

minutes.

(1) For surface BOP systems and surface equipment of a subsea BOP system, a 3-minute test duration is acceptable if you record your test pressures on the outermost half of a 4-hour chart, on a 1-hour chart, or on a digital recorder.

(2) If the equipment does not hold the required pressure during a test, you must remedy the problem and retest the affected component(s).

(d) Additional BOP testing requirements. You must:

(1) Use water to test the surface BOP
system;

(2) Stump test a subsurface BOP system before installation. You must use water to stump test a subsea BOP system. You may use drilling or completion fluids to conduct subsequent tests of a subsea BOP
system;

(3) Alternate tests between control stations and pods. If a control station or pod is not functional, you must suspend further completion operations until that station or pod is operable;

(4) Pressure test the blind or 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; (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 maypostpone 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.


### 64533 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

(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 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, the wellhead, all annuli (A, B, C, D, etc., annuli). (2) subsea wells, the tubing head, the production casing annulus (A annulus). (3) hybrid * wells, the surface wellhead, all annuli at the surface (A and B riser annuli). If the production casing below the mudline and the production casing riser above the mudline are pressure isolated from each other, provisions must bemade 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:

If you have . . . you must monitor . . . with a minimum one pressure data point recorded per

. . .

(a) fixed platform wells, monthly, month for each casing. (b) subsea wells, continuously, day for the production casing. (c) hybrid wells, continuously, day for each riser and/or the production casing. (d) wells operating under a casing pressure request on a

manned fixed platform, daily, day for each casing.

(e) wells operating under a casing pressure request on

an unmanned fixed platform, weekly, week for each casing.

**§ 250.520 When do I have to perform a casing diagnostic test?** 

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


### 64534 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

If you have a . . . you must perform a casing diagnostic test if . . .

(1) fixed platform well, the casing pressure is greater than 100 psig. (2) subsea well, the measurable casing pressure is greater than the external hydrostatic pressure plus 100 psig measured at the subsea wellhead. (3) hybrid well, a riser or the production casing pressure is greater than 100 psig

measured at the surface.

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

**§ 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, immediately. (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 on the production casing (A annulus). The production casing (A annulus) of wells on active gas lift are exempt from diagnostic testing. (c) your casing pressure request becomes invalid, within 30 days. (d) a casing or riser has an increase in pressure greater than 200 psig

over the previous casing diagnostic test, within 30 days.

(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, within 30 days.

(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, once per year, not to exceed 12 months between tests.

(g) your fixed platform well’s outer casing (B, C, D, etc., annuli) has a

pressure exceeding 20 percent of its MIYP, once every 5 years, at a minimum.

**§ 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 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, requirements under § 250.526, submit an Application for Permit to Modify or Corrective Action Plan within 30 days of the diagnostic

test.(b) a casing pressure request, Regional Supervisor, Field Operations, requirements under § 250.527.

**§ 250.526 What must I include in my**

**notification of corrective action?**

The following information must be
included in the notification of corrective

action:

(a) Lessee or Operator name; (b) Area name and OCS block number;

(c) Well name and API number; and

(d) Casing diagnostic test data. **§ 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 H2 S 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?** 

Casing pressure requests are approved by the Regional Supervisor, Field Operations, for a term to be determinedby 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 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; (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 ofoperation. 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 (H2 S) or in zones where the presence of H 2 S is unknown (as defined in § 250.490 of this part), the lessee shall take appropriate precautions


### 64536 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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.

**§ 250.606 Crew instructions.**

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

**§ 250.607 [Reserved]**

**§ 250.608 [Reserved]**

**§ 250.609 Well-workover structures on fixed platforms.** 

Derricks, masts, substructures, and related equipment shall be selected, designed, installed, used, and maintained so as to be adequate for the potential loads and conditions of loading that may be encountered during the operations proposed. Prior tomoving 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 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.**

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 otherrequirements 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.

**§ 250.613 Approval and reporting for well workover operations.** 

(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 H 2 S 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 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 becontinuously 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 wellworkover 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. (2) The expected pressure is 5,000 psi or greater or you use multiple

tubing strings, Four BOPs consisting of an annular, two sets of pipe rams, and one

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

(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. (d) The minimum BOP-system components for well-workover operations with the tree in place and performed through the wellhead insideof conventional tubing using smalldiameter jointed pipe (usually 3 ⁄ 4 inch to

1 1

⁄ 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:

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. Stripper or annular-type well control component. Hydraulically-operated blind rams ...................... Hydraulically-operated blind rams ................... Hydraulically-operated blind rams Hydraulically-operated shear rams ..................... Hydraulically-operated shear rams .................. Hydraulically-operated shear rams.

Kill line inlet ........................................................ Kill line inlet ...................................................... Kill line inlet. Hydraulically-operated two-way slip rams .......... Hydraulically-operated two-way slip rams ....... Hydraulically-operated two-way slip rams. Hydraulically-operated pipe rams. Hydraulically-operated pipe rams ....................... Hydraulically-operated pipe rams .................... Hydraulically-operated blind-shear rams.

These rams should be located as close to the tree as practical. 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.


### 64538 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

(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 sufficientaccumulator 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. (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 thework 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 mustconduct 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 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.


### 64539 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

(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 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 thefollowing 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, the wellhead, all annuli (A, B, C, D, etc., annuli). (ii) subsea wells, the tubing head, the production casing annulus (A annulus). (iii) hybrid* wells, the surface wellhead, all annuli at the surface (A and B riser annuli). If the production casing below the mudline and the production casing riser above the mudline are pressure isolated from each other, provisions must bemade to monitor the production casing below the mudline for casing pressure.

* Characterized as a well drilled with a subsea wellhead and completed with a surface casing head, a surface tubing head, a surface tubing hanger, and a surface christmas tree.

(2) Follow the casing pressure management requirements in subpart E of this part.

(d) Wellhead, tree, and related equipment shall have a pressure rating greater than the shut-in tubing pressure and shall be designed, installed, used, maintained, and tested so as to achieve and maintain pressure control. The tree shall be equipped with a minimum of one master valve and one surface safety valve in the vertical run of the tree
when it is reinstalled.

(e) Subsurface safety equipment shall be installed, maintained, and tested in compliance with § 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: (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.


### 64540 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

(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.

**§ 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 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 notpreviously 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 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 offlowing. 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


### 64541 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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. Alltubing 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.

**§ 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 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, meteringdevices, 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 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,


### 64542 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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-insensor 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 theoperating 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 significant change in operatingpressures. 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 intendedpurpose 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 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


### 64543 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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 additionalrequirements 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. (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 chemicalsystem 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 becapable 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 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-controlprogram 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


### 64544 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

requirements in §§ 250.109 through 250.113 of this part.

**§ 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 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. (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 onewellhead 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


### 64545 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

(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 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 (H 2 S) or in zones where the presence of

H 2 S 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. (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. (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.(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. (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.(4) Convert an existing platform at the current location for a new purpose. (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.


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Activity requiring application and approval Conditions for conducting the activity

(5) Convert an existing mobile offshore drilling unit (MODU) for a new

purpose. (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. **§ 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 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


### 64547 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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), Fixed and floating platform, as appropriate. (2) ANSI/AISC 360–05, Specification for Structural Steel Buildings; (3) API Bulletin 2INT–DG, Interim Guidance for Design of Offshore Structures for Hurricane Conditions; (4) API Bulletin 2INT–EX, Interim Guidance for Assessment of Existing Offshore Structures for Hurricane

Conditions; (5) API Bulletin 2INT–MET, Interim Guidance on Hurricane Conditions in the Gulf of Mexico; (6) API RP 2A–WSD, RP for Planning, Designing, and Constructing Fixed Offshore Platforms—Working

Stress Design;(7) ASTM Standard C 33–07, approved December 15, 2007, Standard Specification for Concrete Aggregates; (8) ASTM Standard C 94/C 94M–07, approved January 1, 2007, Standard Specification for Ready-Mixed

Concrete; (9) ASTM Standard C 150–07, approved May 1, 2007, Standard Specification for Portland Cement;(10) ASTM Standard C 330–05, approved December 15, 2005, Standard Specification for Lightweight Aggregates for Structural Concrete; (11) ASTM Standard C 595–08, approved January 1, 2008, Standard Specification for Blended Hydraulic

Cements; (12) AWS D1.1, Structural Welding Code—Steel; (13) AWS D1.4, Structural Welding Code—Reinforcing Steel; (14) AWS D3.6M, Specification for Underwater Welding; (15) NACE Standard RP 0176–2003, Standard Recommended Practice (RP), Corrosion Control of Steel

Fixed Offshore Platforms Associated with Petroleum Production;(16) ACI 357R–84, Guide for the Design and Construction of Fixed Offshore Concrete Structures, 1984; reapproved 1997, Fixed platforms.

(17) API RP 14J, RP for Design and Hazards Analysis for Offshore Production Facilities; Floating platforms. (18) API RP 2FPS, RP for Planning, Designing, and Constructing, Floating Production Systems; (19) API RP 2RD, Design of Risers for Floating Production Systems (FPSs) and Tension-Leg Platforms

(TLPs); (20) API RP 2SK, RP for Design and Analysis of Station Keeping Systems for Floating Structures; (21) API RP 2T, RP for Planning, Designing, and Constructing Tension Leg Platforms; (22) API RP 2SM, RP for Design, Manufacture, Installation, and Maintenance of Synthetic Fiber Ropes for

Offshore Mooring; (23) API RP 2I, In-Service Inspection of Mooring Hardware for Floating Drilling Units

**§ 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.

**§ 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). (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). 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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Platform Verification Program. The requirements of the Platform Verification Program are described in §§ 250.909 through 250.918 of this subpart. **§ 250.905 How do I get approval for the installation, modification, or repair of my**  **platform?**

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

Required submittal Required contents Other requirements

(a) Application cover letter ................................. Proposed structure 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. You must submit three copies. If, your facilityis subject to the Platform Verification Program (PVP), you must submit four copies.

(b) Location plat ................................................. Latitude and longitude coordinates, Universal Mercator grid-system coordinates, stateplane 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. Your plat must be drawn to a scale of 1 inchequals 2,000 feet and include the coordinates of the lease block boundary lines. You must submit three copies.

(c) Front, Side, and Plan View drawings ........... Platform dimensions and orientation, elevations relative to M.L.L.W. (Mean Lower Low Water), and pile sizes and penetration. Your drawing sizes must not exceed 11 ′′ x 17′′. You must submit three copies (four copies for PVP applications). (d) Complete set of structural drawings ............. 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. Your drawing sizes must not exceed 11 ′′ x 17′′. You must submit one copy.

(e) Summary of environmental data ................... 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. You must submit one copy.

(f) Summary of the engineering design data ..... 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 ortethering systems; fabrication and installation guidelines), and foundation information ( e.g., soil stability, design criteria). You must submit one copy.

(g) Project-specific studies used in the platform

design or installation. All studies pertinent to platform design or installation, e.g., oceanographic and/or soilreports including the overall site investigative report required in § 250.906. You must submit one copy of each study.

(h) Description of the loads imposed on the facility. Loads imposed by jacket; decks; productioncomponents; 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 one copy.


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Required submittal Required contents Other requirements

(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 exceeding0.85 for steel-jacket platform members, indicated on ‘‘line’’ sketches of jacket sections. You must submit one copy.

(j) A copy of the in-service inspection plan ........ This plan is described in § 250.919 ................. You must submit one copy

. (k) Certification statement .................................. 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)’’. An authorized company representative must sign the statement. You must submit one

copy.

(l) Payment of the service fee listed in

§ 250.125.

**§ 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, The results of the analysis must indicate a maximum calculated life of twice the design life of the platform. (2) There is not sufficient structural redundancy to prevent catastrophic

failure of the platform or structure, 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.(2) Your new floating platform is a buoyant offshore facility with a shipshaped hull, 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.

(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. **§ 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; (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 eachphase. 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.

**§ 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 conductedduring 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. (2) For all floating facilities, Ensure that the requirements of the U.S. Coast Guard for structural integrity and stability, e.g., verification of center of gravity, etc., have been met. The CVA must also consider: (i) Drilling, production, and pipeline risers, and riser tensioning systems; (ii) Turrets and turret-and-hull interfaces; (iii) Foundations, foundation pilings and templates, and anchoring systems; and (iv) Mooring or tethering systems.

(c) The CVA must submit interim reports and a final report to the Regional Supervisor, and to you, during the design phase in accordance with the approved schedule required by § 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. (2) For all floating facilities, Ensure that the requirements of the U.S. Coast Guard floating for structural integrity and sta

bility, e.g., verification of center of gravity, etc., have been met. The CVA must also consider: (i) Drilling, production, and pipeline risers, and riser tensioning systems (at least for the initial

fabrication of these elements); (ii) Turrets and turret-and-hull interfaces; (iii) Foundation pilings and templates, and anchoring systems; and (iv) Mooring or tethering systems.

(c) The CVA must submit interim reports and a final report to the Regional Supervisor, and to you, during the fabrication phase in accordance with the approved schedule required by § 250.911(d). In each interim and final report the CVA must:

(1) Give details of how, by whom, and when the independent monitoring activities were conducted; (2) Describe the CVA’s activities during the verification process;

(3) Summarize the CVA’s findings;
(4) Confirm or deny compliance with the design specifications and the approved fabrication plan;

(5) In the final CVA report, make a recommendation to accept or reject the

fabrication unless such a recommendation has been previously made in an interim report; and

(6) Provide any additional comments that the CVA deems necessary.

**§ 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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conducting an independent assessment

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

The CVA must . . . Operation or equipment to be inspected . . .

(1) Verify, as appropriate, (i) Loadout and initial flotation operations; (ii) Towing operations to the specified location, and review the towing records; (iii) Launching and uprighting operations; (iv) Submergence operations; (v) Pile or anchor installations; (vi) Installation of mooring and tethering systems; (vii) Final deck and component installations; and (viii) Installation at the approved location according to the approved design and the installation

plan. (2) Witness (for a fixed or floating platform), (i) The loadout of the jacket, decks, piles, or structures from each fabrication site;(ii) The actual installation of the platform or major modification and the related installation activities. (3) Witness (for a floating platform), (i) The loadout of the platform; (ii) The installation of drilling, production, and pipeline risers, and riser tensioning systems (at

least for the initial installation of these elements); (iii) The installation of turrets and turret-and-hull interfaces; (iv) The installation of foundation pilings and templates, and anchoring systems; and (v) The installation of the mooring and tethering systems. (4) Conduct an onsite survey, Survey the platform after transportation to the approved location.(5) Spot-check as necessary to determine compliance 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, (i) Equipment; (ii) Procedures; and (iii) Recordkeeping.

(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

**§ 250.919 What in-service inspection requirements must I meet?** 

(a) You must submit a comprehensive in-service inspection report annually by November 1 to the Regional Supervisor
that must include:

(1) A list of fixed and floating platforms you inspected in the preceding 12 months;

(2) The extent and area of inspection
for both the above-water and underwater portions of the platform and the pertinent components of the mooring system for floating platforms;

(3) The type of inspection employed ( e.g., visual, magnetic particle, ultrasonic testing);

(4) The overall structural condition of each platform, including a corrosion protection evaluation; and

(5) A summary of the inspection results indicating what repairs, if any,
were needed.

(b) If any of your structures have been exposed to a natural occurrence ( e.g., hurricane, earthquake, or tropical storm), the Regional Supervisor may require you to submit an initial report of all structural damage, followed by subsequent updates, which include the following:

(1) A list of affected structures; (2) A timetable for conducting the inspections described in section 14.4.3 of API RP 2A–WSD (as incorporated by reference in § 250.198); and

(3) An inspection plan for each structure that describes the work you will perform to determine the condition
of the structure.

(c) The Regional Supervisor may also require you to submit the results of the inspections referred to in paragraph (b)(2) of this section, including a description of any detected damage that may adversely affect structural integrity, an assessment of the structure’s ability to withstand any anticipated environmental conditions, and any remediation plans. Under §§ 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** 

**§ 250.1000 General requirements.**

(a) Pipelines and associated valves, flanges, and fittings shall be designed, installed, operated, maintained, and abandoned to provide safe and pollution-free transportation of fluids in a manner which does not unduly
interfere with other uses in the Outer Continental Shelf (OCS).

(b) An application must be accompanied by payment of the service fee listed in § 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, ifthe 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, ifpractical, 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. (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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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 alsosuspend pipeline operations or a rightof-way grant if the Regional Supervisordetermines 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).

**§ 250.1001 Definitions.**

Terms used in this subpart shall have the meanings given below:

DOI pipelines include: (1) Producer-operated pipelines extending upstream (generally seaward) from each point on the OCS at which operating responsibility transfers from a producing operator to a transporting
operator;

(2) Producer-operated pipelines extending upstream (generally seaward) of the last valve (including associated safety equipment) on the last production facility on the OCS that do not connect to a transporter-operated pipeline on the OCS before crossing into State waters;

(3) Producer-operated pipelines connecting production facilities on the
OCS;

(4) Transporter-operated pipelines that DOI and DOT have agreed are to be regulated as DOI pipelines; and

(5) All OCS pipelines not subject to regulation under 49 CFR parts 192 and

195.

DOT pipelines include: (1) Transporter-operated pipelines currently operated under DOT requirements governing design, construction, maintenance, and operation; (2) Producer-operated pipelines that DOI and DOT have agreed are to be regulated under DOT requirements governing design, construction, maintenance, and operation; and

(3) Producer-operated pipelines downstream (generally shoreward) of the last valve (including associated safety equipment) on the last production facility on the OCS that do not connect to a transporter-operated pipeline on the OCS before crossing into State waters and that are regulated under 49 CFR parts 192 and 195.

Lease term pipelines are those pipelines owned and operated by a lessee or operator and are wholly
contained within the boundaries of a single lease, unitized leases, or contiguous (not cornering) leases of that lessee or operator.

Out-of-service pipelines are those pipelines that have not been used to transport oil, natural gas, sulfur, or produced water for more than 30 consecutive days.

Pipelines are the piping, risers, and appurtenances installed for the purpose of transporting oil, gas, sulphur, and produced water. (Piping confined to a production platform or structure is covered in Subpart H, Production Safety Systems, and is excluded from this subpart.)

Production facilities means OCS facilities that receive hydrocarbon production either directly from wells or from other facilities that produce hydrocarbons from wells. They may include processing equipment for treating the production or separating it into its various liquid and gaseous components before transporting it to
shore.

Right-of-way pipelines are those pipelines which—

(1) Are contained within the boundaries of a single lease or group of
unitized leases but are not owned and operated by the lessee or operator of that lease or unit,

(2) Are contained within the boundaries of contiguous (not cornering) leases which do not have a common lessee or operator,

(3) Are contained within the boundaries of contiguous (not cornering) leases which have a common lessee or operator but are not owned and operated by that common lessee or
operator, or

(4) Cross any portion of an unleased block(s).

**§ 250.1002 Design requirements for DOI pipelines.** 

(a) The internal design pressure for steel pipe shall be determined in accordance with the following formula: 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 thatexceed 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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(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.

**§ 250.1003 Installation, testing, and repair requirements for DOI pipelines.** 

(a)(1) Pipelines greater than 8 5 ⁄ 8 inches in diameter and installed in water depths of less than 200 feet shall be buried to a depth of at least 3 feet unless they are located in pipeline congested areas or seismically active areas as determined by the Regional Supervisor. Nevertheless, the Regional Supervisor may require burial of any pipeline if the Regional Supervisor
determines that such burial will reduce
the likelihood of environmental degradation or that the pipeline may constitute a hazard to trawling operations or other uses. A trawl test or diver survey may be required to determine whether or not pipeline burial is necessary or to determine whether a pipeline has been properly
buried.

(2) Pipeline valves, taps, tie-ins, capped lines, and repaired sections that could be obstructive shall be provided
with at least 3 feet of cover unless the Regional Supervisor determines that such items present no hazard to trawling or other operations. A protective device may be used to cover an obstruction in lieu of burial if it is approved by the Regional Supervisor prior to installation.

(3) Pipelines shall be installed with a minimum separation of 18 inches at pipeline crossings and from
obstructions.

(4) Pipeline risers installed after April 1, 1988, shall be protected from physical damage that could result from contact with floating vessels. Riser protection on pipelines installed on or before April 1, 1988, may be required when the Regional Supervisor determines that significant damage potential exists.

(b)(1) Pipelines shall be pressure
tested with water at a stabilized pressure of at least 1.25 times the MAOP for at least 8 hours when installed, relocated, uprated, or reactivated after being out-of-service for more than 1

year.

(2) Prior to returning a pipeline to service after a repair, the pipeline shall be pressure tested with water or processed natural gas at a minimum stabilized pressure of at least 1.25 times
the MAOP for at least 2 hours.

(3) Pipelines shall not be pressure tested at a pressure which produces a stress in the pipeline in excess of 95 percent of the specified minimum-yield strength of the pipeline. A temperature recorder measuring test fluid temperature synchronized with a pressure recorder along with deadweight test readings shall be employed for all pressure testing. When a pipeline is pressure tested, no observable leakage shall be allowed. Pressure gauges and recorders shall be of sufficient accuracy to verify that leakage is not occurring.

(4) The Regional Supervisor may require pressure testing of pipelines to verify the integrity of the system when the Regional Supervisor determines that
there is a reasonable likelihood that the line has been damaged or weakened by
external or internal conditions.

(c) When a pipeline is repaired utilizing a clamp, the clamp shall be a full encirclement clamp able to withstand the anticipated pipeline

pressure.

**§ 250.1004 Safety equipment requirements for DOI pipelines.** 

(a) The lessee shall ensure the proper installation, operation, and maintenance of safety devices required by this section on all incoming, departing, and crossing pipelines on platforms.

(b)(1)(i) Incoming pipelines to a platform shall be equipped with a flow safety valve (FSV).

(ii) For sulphur operations, incoming pipelines delivering gas to the power plant platform may be equipped with high- and low-pressure sensors (PSHL),
which activate audible and visual alarms in lieu of requirements in paragraph (b)(1)(i) of this section. The PSHL shall be set at 15 percent or 5 psi, whichever is greater, above and below the normal operating pressure range.

(2) Incoming pipelines boarding a production platform shall be equipped
with an automatic shutdown valve (SDV) immediately upon boarding the platform. The SDV shall be connected to the automatic- and remote-emergency shut-in systems.

(3) Departing pipelines receiving production from production facilitiesshall 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 andconnected 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 calculated or calculations indicate a life expectancy of less than 20 years, such pipelines shall be inspected annually bytaking 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, Isolate the pipeline with a blind flange or a closed block valve at each end of the pipeline. (2) More than 1 year but less than 5 years, Flush and fill the pipeline with inhibited seawater. (3) 5 or more years, Decommission the pipeline according to §§ 250.1750–250.1754.

**§ 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, andtype 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, compressors, and vessels; maximum input pressure(s); the rated working pressure, as specified by ANSI or API, of all valves, flanges, and fittings; the initial receiving equipment and its rated working pressure; and associated safety equipment and pig launchers and
receivers. The schematic must indicate the point on the OCS at which operating responsibility transfers between a producing operator and a transporting
operator.

(3) General information as follows: (i) Description of cathodic protection system. If pipeline anodes are to be used, specify the type, size, weight, number, spacing, and anticipated life;

(ii) Description of external pipeline coating system;

(iii) Description of internal protective

measures;

(iv) Specific gravity of the empty pipe; (v) MSP; (vi) MAOP and calculations used in its determination;

(vii) Hydrostatic test pressure, medium, and period of time that the line will be tested;

(viii) MAOP of the receiving pipeline or facility,

(ix) Proposed date for commencing
installation and estimated time for construction; and

(x) Type of protection to be afforded crossing pipelines, subsea valves, taps, and manifold assemblies, if applicable.

(4) A description of any additional design precautions you took to enable the pipeline to withstand the effects of water currents, storm or ice scouring, soft bottoms, mudslides, earthquakes, permafrost, and other environmental
factors.

(i) If you propose to use unbonded flexible pipe, your application must
include:

(A) The manufacturer’s design specification sheet; (B) The design pressure (psi); (C) An identification of the design standards you used; and

(D) A review by a third-party independent verification agent (IVA) according to API Spec 17J (as incorporated by reference in § 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 anapproved 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 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 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 whileconducting 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 bekept 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 paythe 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 andnondiscriminatory 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 [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. (2) Your accessory site is located in water

depths of 200 meters or greater; 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.

(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, BSEEmay 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 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 right of-way grants.** 

(a) You must submit an original and three copies of an application for a new or modified pipeline ROW grant to the Regional Supervisor. The application must address those items required by § 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 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 isintersected 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.

**§ 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 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 itsconsent 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 mayprescribe, as conditions to the right-ofway grant, stipulations necessary to protect human, marine, and coastal environments, life (including aquatic life), property, and mineral resourceslocated 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 adeviation from the proposed right-ofway as granted has occurred, the rightof-way holder shall— (i) Notify the operators of all leases and holders of all right-of-way grants in which a deviation has occurred, and within 60 days of the date of the acceptance by the Regional Supervisor of the completion of pipeline construction report, provide the Regional Supervisor with evidence of such notification; and

(ii) Relinquish any unused portion of the right-of-way.

(3) Substantial deviation of a right-ofway pipeline as constructed from the proposed right-of-way as granted may begrounds 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-of way grants.** 

(a) Assignment may be made of a right-of-way grant, in whole or of any lineal segment thereof, subject to the approval of the Regional Supervisor. An application for approval of an assignment of a right-of-way or of a lineal segment thereof, shall be filed in triplicate with the Regional Supervisor.

(b) Any application for approval for an assignment, in whole or in part, ofany 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 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. (2) At least one well test during a calendar half-year for each producing

completion, 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.

(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.

**§ 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 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 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 H 2S. 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.

(2) During the restart of a facility that was shut in because of weather

conditions, such as a hurricane. Flaring or venting may not exceed 48 cumulative hours without Regional Supervisor approval. (3) During the blow down of transportation pipelines downstream of the

royalty meter. (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.(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. 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.(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. You may not flare or vent more than an average of 50 MCF per day during any calendar month without Regional Supervisor approval.

(6) When the equipment works properly but there is a temporary upset

condition, such as a hydrate or paraffin plug. (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.(7) When equipment fails to work properly, during equipment maintenance and repair, or when you must relieve system pressures. (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.

(b) Regardless of the requirements in paragraph (a) of this section, you must not flare or vent gas over the volume approved in your Development Operations Coordination Document (DOCD) or your Development and Production Plan (DPP) submitted to

BOEM.

(c) The Regional Supervisor may establish alternative approval procedures to cover situations when you cannot contact the BSEE office, such as during non-office hours.

(d) The Regional Supervisor may specify a volume limit, or a shorter time limit than specified elsewhere in this


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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.

**§ 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 thattransporting 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 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. (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 H**  2**S?**

(a) You may not vent gas containing

H 2 S, except for minor releases during maintenance and repair activities that
do not result in a 15-minute timeVerDate Mar<15>2010 16:55 Oct 17, 2011 Jkt 226001 PO 00000 Frm 00133 Fmt 4701 Sfmt 4700 E:\FR\FM\18OCR2.SGM 18OCR2mstockstill on DSK4VPTVN1PROD with RULES2

### 64564 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

weighted average atmosphere
concentration of H 2 S of 20 ppm or higher anywhere on the platform.

(b) You may flare gas containing H 2 S 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 H 2 S. The Regional Supervisor will use information provided in the lessee’s H 2 S 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 H2 S. Each report must contain, on a daily
basis:

(1) The volume and duration of each flaring and venting occurrence; (2) H 2 S concentration in the flared or vented gas; and

(3) The calculated amount of SO 2 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:

WPT BSEE–
0126 (2 copies) Gas cap production Downhole commingling Production within 500-ft of
a unit or lease
line

(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 ................................................................................ ........................ ✔ ✔

........................


### 64565 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

WPT BSEE–
0126 (2 copies) Gas cap production Downhole commingling Production within 500-ft of
a unit or lease
line

(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 ......................................................................... ........................ ✔ ✔ ✔

✔ 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 Question index table.**

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

Frequently asked questions CFR citation

1. What are the requirements for measuring liquid hydrocarbons? § 250.1202(a) 2. What are the requirements for liquid hydrocarbon royalty meters? § 250.1202(b) 3. What are the requirements for run tickets? § 250.1202(c) 4. What are the requirements for liquid hydrocarbon royalty meter provings? § 250.1202(d) 5. What are the requirements for calibrating a master meter used in royalty meter provings? § 250.1202(e) 6. What are the requirements for calibrating mechanical-displacement provers and tank provers? § 250.1202(f) 7. What correction factors must a lessee use when proving meters with a mechanical displacement prover, tank prover, or

master meter? § 250.1202(g)

8. What are the requirements for establishing and applying operating meter factors for liquid hydrocarbons? § 250.1202(h)9. Under what circumstances does a liquid hydrocarbon royalty meter need to be taken out of service, and what must a lessee do? § 250.1202(i)

10. How must a lessee correct gross liquid hydrocarbon volumes to standard conditions? § 250.1202(j) 11. What are the requirements for liquid hydrocarbon allocation meters? § 250.1202(k) 12. What are the requirements for royalty and inventory tank facilities? § 250.1202(l) 13. To which meters do BSEE requirements for gas measurement apply? § 250.1203(a) 14. What are the requirements for measuring gas? § 250.1203(b) 15. What are the requirements for gas meter calibrations? § 250.1203(c) 16. What must a lessee do if a gas meter is out of calibration or malfunctioning? § 250.1203(d)17. What are the requirements when natural gas from a Federal lease is transferred to a gas plant before royalty determination? § 250.1203(e)

18. What are the requirements for measuring gas lost or used on a lease? § 250.1203(f) 19. What are the requirements for the surface commingling of production? § 250.1204(a) 20. What are the requirements for a periodic well test used for allocation? § 250.1204(b) 21. What are the requirements for site security? § 250.1205(a) 22. What are the requirements for using seals? § 250.1205(b)

**§ 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 attributable to one or more platforms, leases, units, or wells, in relation to the total production from a royalty or allocation measurement point.

API MPMS —the American Petroleum

Institute’s Manual of Petroleum Measurement Standards, chapters 1, 20,

and 21. British Thermal Unit (Btu) —the

amount of heat needed to raise the temperature of one pound of water from 59.5 degrees Fahrenheit (59.5 ° F) to 60.5 degrees Fahrenheit (60.5 ° F) at standard pressure base (14.73 pounds per square inch absolute (psia)).


### 64566 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

Compositional Analysis—separating mixtures into identifiable components expressed in mole percent.

Force majeure event —an event beyond your control such as war, act of terrorism, crime, or act of nature which prevents you from operating the wells and meters on your OCS facility.

Gas lost —gas that is neither sold nor
used on the lease or unit nor used internally by the producer.

Gas processing plant —an installation that uses any process designed to remove elements or compounds (hydrocarbon and non-hydrocarbon) from gas, including absorption, adsorption, or refrigeration. Processing does not include treatment operations, including those necessary to put gas
into marketable conditions such as natural pressure reduction, mechanical separation, heating, cooling, dehydration, desulphurization, and compression. The changing of pressures or temperatures in a reservoir is not processing.

Gas processing plant statement —a monthly statement showing the volume and quality of the inlet or field gas stream and the plant products recovered during the period, volume of plant fuel, flare and shrinkage, and the allocation
of these volumes to the sources of the
inlet stream.

Gas royalty meter malfunction—an error in any component of the gas measurement system which exceeds
contractual tolerances.

Gas volume statement —a monthly statement showing gas measurement data, including the volume (Mcf) and quality (Btu) of natural gas which flowed through a meter.

Inventory tank —a tank in which liquid hydrocarbons are stored prior to royalty measurement. The measured volumes are used in the allocation

process.

Liquid hydrocarbons (free liquids)

— hydrocarbons which exist in liquid form at standard conditions after passing through separating facilities.

Malfunction factor —a liquid hydrocarbon royalty meter factor that differs from the previous meter factor by an amount greater than 0.0025.

Natural gas—a highly compressible, highly expandable mixture of hydrocarbons which occurs naturally in a gaseous form and passes a meter in vapor phase.

Operating meter —a royalty or allocation meter that is used for gas or liquid hydrocarbon measurement for any period during a calibration cycle.

Pipeline (retrograde) condensate

— liquid hydrocarbons which drop out of the separated gas stream at any point in a pipeline during transmission to shore.

Pressure base—the pressure at which gas volumes and quality are reported. The standard pressure base is 14.73 psia.

Prove—to determine (as in meter proving) the relationship between the volume passing through a meter at one
set of conditions and the indicated
volume at those same conditions.

Royalty meter —a meter approved for the purpose of determining the volume of gas, oil, or other components removed, saved, or sold from a Federal
lease.

Royalty tank —an approved tank in which liquid hydrocarbons are measured and upon which royalty
volumes are based.

Run ticket —the invoice for liquid hydrocarbons measured at a royalty point.

Sales meter —a meter at which custody transfer takes place (not necessarily a royalty meter). Seal —a device or approved method used to prevent tampering with royalty
measurement components.

Standard conditions—atmospheric pressure of 14.73 pounds per square inch absolute (psia) and 60 ° 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).

**§ 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.

Application type Actions

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

(2) Use measurement equipment that will accurately measure the liquid hydrocarbons produced from a lease or
unit;

(3) Use procedures and correction factors according to the applicable chapters of the API MPMS as incorporated by reference in § 250.198, when obtaining net standard volume
and associated measurement parameters; and

(4) When requested by the Regional Supervisor, provide the pipeline (retrograde) condensate volumes as

allocated to the individual leases or

units.

(b) What are the requirements for liquid hydrocarbon royalty meters? You

must:

(1) Ensure that the royalty meter facilities include the followingapproved components (or other BSEEapproved components) which must be compatible with their connected
systems: (i) A meter equipped with a nonreset totalizer;

(ii) A calibrated mechanical displacement (pipe) prover, master meter, or tank prover;

(iii) A proportional-to-flow sampling device pulsed by the meter output;

(iv) A temperature measurement or temperature compensation device; and

(v) A sediment and water monitor with a probe located upstream of the
divert valve.


### 64567 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

(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; (d) What are the requirements for liquid hydrocarbon royalty meter provings? You must:

(1) Permit BSEE representatives to witness provings;

(2) Ensure that the integrity of the prover calibration is traceable to test measures certified by the National Institute of Standards and Technology;

(3) Prove each operating royalty meter to determine the meter factor monthly,
but the time between meter factor
determinations must not exceed 42 days. When a force majeure event precludes the required monthly meter proving, meters must be proved within 15 days after being returned to service. The meters must be proved monthly thereafter, but the time between meter
factor determinations must not exceed 42 days;

(4) Obtain approval from the Regional Supervisor before proving on a schedule other than monthly; and

(5) Submit copies of all meter proving reports for royalty meters to the Regional Supervisor monthly within 15 days after the end of the month.

(e) What are the requirements for calibrating a master meter used in royalty meter provings? You must:

(1) Calibrate the master meter to obtain a master meter factor before using it to determine operating meter factors;

(2) Use a fluid of similar gravity, viscosity, temperature, and flow rate as the liquid hydrocarbons that flow through the operating meter to calibrate the master meter;

(3) Calibrate the master meter monthly, but the time between calibrations must not exceed 42 days;

(4) Calibrate the master meter by recording runs until the results of two consecutive runs (if a tank prover is used) or five out of six consecutive runs (if a mechanical-displacement prover is used) produce meter factor differences of no greater than 0.0002. Lessees must use the average of the two (or the five) runs that produced acceptable results to compute the master meter factor;

(5) Install the master meter upstream of any back-pressure or reverse flow
check valves associated with the operating meter. However, the master meter may be installed either upstream or downstream of the operating meter;
and

(6) Keep a copy of the master meter calibration report at your field location for 2 years.

(f) What are the requirements for calibrating mechanical-displacement provers and tank provers? You must:

(1) Calibrate mechanical-displacement provers and tank provers at least once every 5 years according to the API MPMS (as incorporated by reference in § 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 usewhen 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


### 64568 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

(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 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 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


### 64569 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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.

**§ 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: (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. (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 What is the purpose of this subpart?** 

This subpart explains how Outer Continental Shelf (OCS) leases are unitized. If you are an OCS lessee, use the regulations in this subpart for both competitive reservoir and unitization situations. The purpose of joint development and unitization is to:

(a) Conserve natural resources; (b) Prevent waste; and/or (c) Protect correlative rights, including Federal royalty interests.

**§ 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


### 64570 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

substances, and the unit operator nolonger 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 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 § 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. **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. § 250.1402

What is the maximum civil

penalty? § 250.1403

Which violations will BSEE

review for potential civil penalties? § 250.1404

When is a case file developed? § 250.1405

When will BSEE notify me

and provide penalty information? § 250.1406

How do I respond to the letter of notification? § 250.1407

When will I be notified of the

Reviewing Officer’s decision? § 250.1408

What are my appeal rights? § 250.1409

**§ 250.1402 Definitions.**

Terms used in this subpart have the following meaning:

Case file means a BSEE document file containing information and the record of evidence related to the alleged
violation.

Civil penalty means a fine. It is a BSEE regulatory enforcement tool used
in addition to Notices of Incidents of Noncompliance and directed suspensions of production or other operations.

Reviewing Officer means a BSEE employee assigned to review case files and assess civil penalties.

Violation means failure to comply
with the Outer Continental Shelf Lands Act (OCSLA) or any other applicable laws, with any regulations issued under the OCSLA, or with the terms or provisions of leases, licenses, permits, rights-of-way, or other approvals issued
under the OCSLA.

Violator means a person responsible
for a violation. **§ 250.1403 What is the maximum civil penalty?** 

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 When is a case file developed?**

BSEE will develop a case file during its investigation of the violation, and forward it to a Reviewing Officer if any of the conditions in § 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.

**§ 250.1406 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.

**§ 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 penaltywas 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 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 What definitions apply to this subpart?** 

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

Penalties After a Period To Correct

**§ 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 What if I do not correct the**

**violation?**

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

(b) If you do not correct all of the
violations identified in the Notice of Noncompliance within 40 days after you receive the Notice of Noncompliance (or 20 days following the expiration of a longer time period specified in that Notice), we may increase the penalty to up to $5,000 per day, beginning with the date of the Notice of Noncompliance, for each violation for as long as you do not
correct the violations.

**§ 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?** 

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 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 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 How may BSEE collect the penalty?** 

(a) BSEE may use all available means to collect the penalty including, but not
limited to:

(1) Requiring the lease surety, for amounts owed by lessees, to pay the penalty;

(2) Deducting the amount of the penalty from any sums the United States owes to you; and

(3) Using judicial process to compel your payment under 30 U.S.C. 1719(k).

(b) If the Department uses judicial process, or if you seek judicial review under § 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.

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 to any authority for prosecution under
other statutes.

Bonding Requirements

**§ 250.1490 What standards must my BOEM-specified surety instrument meet?** 

(a) A BOEM-specified surety instrument must be in a form specified in BOEM instructions. BSEE will give you written information and standard forms for BOEM-specified surety instrument requirements.

(b) BOEM will use a bank-rating
service to determine whether a financial institution has an acceptable rating to provide a surety instrument adequate to indemnify the lessor from loss or damage.

(1) Administrative appeal bonds must be issued by a qualified surety company which the Department of the Treasury has approved.

(2) Irrevocable letters of credit or certificates of deposit must be from a financial institution acceptable to BOEM with a minimum 1-year period of coverage subject to automatic renewal
up to 5 years.

**§ 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 (2) Submit a separate surety
instrument for new amounts under appeal until you amend the instrument to cover the new appeals.

Financial Solvency Requirements

**§ 250.1495 How do I demonstrate financial solvency?** 

(a) To demonstrate financial solvency under this part, you must submit an audited consolidated balance sheet, and,if requested by the BOEM 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 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 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 What is the goal of my training program?** 

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

**§ 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 May I use alternative training**

**methods?**

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

**§ 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.

**§ 250.1507 How will BSEE measure training results?** 

BSEE may periodically assess your training program, using one or more of
the methods in this section.

(a) Training system audit. BSEE or its authorized representative may conduct a training system audit at your office. The training system audit will compare your training program against this subpart. You must be prepared to explain your overall training program and produce evidence to support your explanation.

(b) Employee or contract personnel

interviews. BSEE or its authorized representative may conduct interviews
at either onshore or offshore locations to inquire about the types of training that were provided, when and where this training was conducted, and how effective the training was. (c) Employee or contract personnel testing. BSEE or its authorized representative may conduct testing at
either onshore or offshore locations for the purpose of evaluating an individual’s knowledge and skills in perfecting well control, deepwater well control, and production safety duties.

(d) Hands-on production safety, simulator, or live well testing. BSEE or its authorized representative may
conduct tests at either onshore or
offshore locations. Tests will be designed to evaluate the competency of your employees or contract personnel in performing their assigned well control, deepwater well control, and production safety duties. You are responsible for the costs associated with this testing, excluding salary and travel costs for BSEE personnel.

**§ 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); (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 Determination of sulphur deposit.** 

(a) Upon receipt of a written request from the lessee, the District Manager will determine whether a sulphur deposit has been defined that contains sulphur in paying quantities (i.e., sulphur in quantities sufficient to yield a return in excess of the costs, after completion of the wells, of producing minerals at the wellheads).

(b) A determination under paragraph (a) of this section shall be based upon the following:

(1) Core analyses that indicate the presence of a producible sulphur deposit (including an assay of elemental sulphur);

(2) An estimate of the amount of recoverable sulphur in long tons over a specified period of time; and

(3) Contour map of the cap rock together with isopach map showing the
extent and estimated thickness of the sulphur deposit.

**§ 250.1604 General requirements.**

Sulphur lessees shall comply with requirements of this section whenconducting well-drilling, wellcompletion, well-workover, or production operations.

(a) Equipment movement. Themovement 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 (H 2 S). When adrilling, well-completion, wellworkover, or production operation is being conducted on a well in zones
known to contain H 2 S or in zones where the presence of H 2 S 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

H2 S 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 indrilling, 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 movingequipment 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 properoperation 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 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 iscapable 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 shallbe 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 attendedmust be equipped with either remoteoperated manual or automaticshutdown devices. Diesel engines that are not continuously attended must be 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 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. **§ 250.1609 Pressure testing of casing.** (a) Prior to drilling the plug after cementing, all casing strings, except the drive or structural casing, shall be pressure tested. The conductor casing shall be tested to at least 200 psi. All casing strings below the conductor casing shall be tested to 500 psi or 0.22 psi/ft, whichever is greater. (When oil or gas is not present in the cap rock, the production liner need not be cemented in place; thus, it would not be subject to pressure testing.) If the pressure declines more than 10 percent in 30
minutes or if there is another indication of a leak, the casing shall be recemented, repaired, or an additional casing string run and the casing tested again. The above procedures shall be repeated until a satisfactory test is obtained. The time, conditions of testing, and results of all casing pressure
tests shall be recorded in the driller’s
report.

(b) After cementing any string of casing other than structural, drilling
shall not be resumed until there has been a timelapse of at least 8 hours under pressure for the conductor casing string or 12 hours under pressure for all other casing strings. Cement is considered under pressure if one or
more float valves are shown to be holding the cement in place or when other means of holding pressure are
used.

**§ 250.1610 Blowout preventer systems and system components.** 

(a) General. The blowout preventer (BOP) systems and system components shall be designed, installed, used, maintained, and tested to assure well
control.

(b) BOP stacks. The BOP stacks shall consist of an annular preventer and the number of ram-type preventers as specified under paragraphs (e) and (f) of this section. The pipe rams shall be of proper size to fit the drill pipe in use.

(c) Working pressure. The workingpressure rating of any BOP shall exceed the surface pressure to which it may be anticipated to be subjected.

(d) BOP equipment. All BOP systems shall be equipped and provided with the following:

(1) An accumulator system that provides sufficient capacity to supply 1.5 times the volume necessary to close and hold closed all BOP equipment units with a minimum pressure of 200 psi above the precharge pressure, without assistance from a charging system. Accumulator regulators supplied by rig air that do not have a secondary source of pneumatic supply must be equipped with manual overrides or other devices alternately provided to ensure capability of hydraulic operations if rig air is lost.

(2) An automatic backup to the accumulator system. The backup system shall be supplied by a power source independent from the power source to the primary accumulator system. The automatic backup system shall possess sufficient capability to close the BOP
and hold it closed.

(3) At least one operable remote BOP
control station in addition to the one on the drilling floor. This control station shall be in a readily accessible location away from the drilling floor.

(4) A drilling spool with side outlets, if side outlets are not provided in the body of the BOP stack, to provide for separate kill and choke lines.

(5) A choke line and a kill line each equipped with two full-opening valves.
At least one of the valves on the choke
line and one valve on the kill line shall be remotely controlled, except that a check valve may be installed on the kill line in lieu of the remotely controlled valve, provided that two readily accessible manual valves are in place and the check valve is placed between the manual valve and the pump.

(6) A fill-up line above the uppermost
preventer.

(7) A choke manifold designed with consideration of anticipated pressures to which it may be subjected, method of well control to be employed, surrounding environment, and corrosiveness, volume, and abrasiveness
of fluids. The choke manifold shall also meet the following requirements:

(i) Manifold and choke equipment subject to well and/or pump pressure shall have a rated working pressure at least as great as the rated working pressure of the ram-type BOP’s or as otherwise approved by the District Manager;

(ii) All components of the choke manifold system shall be protected from freezing by heating, draining, or filling with proper fluids; and

(iii) When buffer tanks are installed
downstream of the choke assemblies for the purpose of manifolding the bleed lines together, isolation valves shall be
installed on each line.

(8) Valves, pipes, flexible steel hoses, and other fittings upstream of, and including, the choke manifold with a pressure rating at least as great as the rated working pressure of the ram-type BOP’s unless otherwise approved by the District Manager.

(9) A wellhead assembly with a rated working pressure that exceeds the pressure to which it might be subjected.

(10) The following system
components:


### 64580 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

(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.

**§ 250.1611 Blowout preventer systems tests, actuations, inspections, and** 

**maintenance.**

(a) Prior to conducting high-pressure tests, all BOP systems shall be tested to a pressure of 200 to 300 psi.

(b) Ram-type BOP’s and the choke manifold shall be pressure tested with water to rated working pressure or as otherwise approved by the District Manager. Annular type BOP’s shall be pressure tested with water to 70 percent of rated working pressure or as otherwise approved by the District Manager.

(c) In conjunction with the weekly pressure test of BOP systems required in paragraph (d) of this section, the choke manifold valves, upper and lower kelly cocks, and drill-string safety valves shall be pressure tested to pipe-ram test pressures. Safety valves with proper casing connections shall be actuated prior to running casing.

(d) BOP system shall be pressure
tested as follows:

(1) When installed; (2) Before drilling out each string of casing or before continuing operations in cases where cement is not drilled out;

(3) At least once each week, but not exceeding 7 days between pressure tests, alternating between control stations. If either control system is not functional, further drilling operations shall be suspended until that system becomes operable. A period of more than 7 days between BOP tests is allowed when there is a stuck drill pipe or there are pressure control operations and remedial efforts are being performed, provided that the pressure tests are conducted as soon as possible and before normal operations resume. The date, time, and reason for postponing pressure testing shall be entered into the driller’s report. Pressure testing shall be performed at intervals to allow each drilling crew to operate the equipment. The weekly pressure test is not required for blind and blind-shear

rams;

(4) Blind and blind-shear rams shall be actuated at least once every 7 days.Closing pressure on the blind and 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 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


### 64581 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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.

**§ 250.1615 Securing of wells.**

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

**§ 250.1616 Supervision, surveillance, and training.** 

(a) The lessee shall provide onsite supervision of drilling operations at all

times.

(b) From the time drilling operations
are initiated and until the well is completed or abandoned, a member of the drilling crew or the toolpusher shall maintain rig-floor surveillance continuously, unless the well is secured with BOP’s, bridge plugs, packers, or cement plugs.

(c) Lessee and drilling contractor personnel shall be trained and qualified in accordance with the provisions of subpart O of this part. Records of specific training that lessee and drilling contractor personnel have successfully completed, the dates of completion, and
the names and dates of the courses shall
be maintained at the drill site.

**§ 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; (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,


### 64582 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

(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 H 2 S 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 Application for permit to modify.** 

(a) You must submit requests for changes in plans, changes in major drilling equipment, proposals to deepen, sidetrack, complete, workover, or plug back a well, or engage in similar activities to the District Manager on Form BSEE–0124, Application for Permit to Modify (APM). The submission of your APM must be accompanied by payment of the service fee listed in § 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.

**§ 250.1619 Well records.**

(a) Complete and accurate records for each well and all well operations shall be retained for a period of 2 years at the
lessee’s field office nearest the OCS facility or at another location conveniently available to the District Manager. The records shall contain a description of any significant malfunction or problem; all the formations penetrated; the content and character of sulphur in each formation if cored and analyzed; the kind, weight, size, grade, and setting depth of casing; all well logs and surveys run in the wellbore; and all other information required by the District Manager in the interests of resource evaluation, prevention of waste, conservation of natural resources, protection of correlative rights, safety of operations, and environmental protection.

(b) When drilling operations are suspended or temporarily prohibited under the provisions of § 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 well workover 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 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 H 2 S or zones where the presence of H 2 S 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


### 64583 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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 becontinuously 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.

**§ 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 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 1 1 ⁄ 4 inch) as a work string; i.e., small-tubing operations, shall consist of the following: (1) For air line changes, the well shall be killed prior to beginning operations. The procedures for killing the well shallbe 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 maintainedon 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


### 64584 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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 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 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


### 64585 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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). (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 availableto 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. (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 chemicalsystem 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).


### 64586 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

(ii) All detection systems shall becapable 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.

**§ 250.1630 Safety-system testing and**

**records.**

(a) Inspection and testing. You must inspect and successfully test safety system devices at the interval specified below or more frequently if operating conditions warrant. Testing must be in accordance with API RP 14C, Appendix D (as incorporated by reference in § 250.198). For safety system devices other than those listed in API RP 14C, Appendix D, you must utilize the analysis technique and documentation specified therein for inspection and testing of these components, and the following:

(1) Safety relief valves on the natural gas feed system for power plant operations such as pressure safety valves shall be inspected and tested for operation at least once every 12 months.
These valves shall be either bench tested or equipped to permit testing with an external pressure source.

(2) The following safety devices (excluding electronic pressure transmitters and level sensors) must be inspected and tested at least once each calendar month, but at no time may more than 6 weeks elapse between tests:

(i) All pressure safety high or pressure safety low, and

(ii) All level safety high and level safety low controls.

(3) The following electronic pressure
transmitters and level sensors must be inspected and tested at least once every 3 months, but at no time may more than 120 days elapse between tests:

(i) All PSH or PSL, and (ii) All LSH and LSL controls. (4) All pumps for firewater systems shall be inspected and operated weekly.

(5) All fire- (flame, heat, or smoke) and gas-detection systems shall be inspected and tested for operation and recalibrated every 3 months provided that testing can be performed in a
nondestructive manner.

(6) Prior to the commencement of production, the lessee shall notify the District Manager when the lessee is ready to conduct a preproduction test and inspection of the safety system. The lessee shall also notify the District Manager upon commencement of production in order that a complete inspection may be conducted.

(b) Records. The lessee shall maintain records for a period of 2 years for each safety device installed. These records shall be maintained by the lessee at the
lessee’s field office nearest the OCS facility or another location conveniently available to the District Manager. These
records shall be available for BSEE
review. The records shall show the present status and history of each safety device, including dates and details of installation, removal, inspection, testing, repairing, adjustments, and
reinstallation.

**§ 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., 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,


### 64587 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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 facilitiesinstalled 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. **§ 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.



### D ECOMMISSIONING 

### A PPLICATIONS AND 

### R EPORTS 

### TABLE

Decommissioning applications and reports When to submit Instructions

(a) Initial platform removal application [not required in

the Gulf of Mexico OCS Region]. 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. Include information required under § 250.1726.

(b) Final removal application for a platform or other

facility. Before removing a platform or other facility in the Gulf of Mexico OCS Region, or not more than 2years after the submittal of an initial platform removal application to the Pacific OCS Region and the Alaska OCS Region. Include information required under § 250.1727.

(c) Post-removal report for a platform or other facility Within 30 days after you remove a platform or other facility. Include information required under § 250.1729. (d) Pipeline decommissioning application ................... Before you decommission a pipeline ........................ Include in formation required under § 250.1751(a) or § 250.1752(a), as applicable. (e) Post-pipeline decommissioning report ................... Within 30 days after you decommission a pipeline ... Include informati on required under § 250.1753. (f) Site clearance report for a platform or other facility Within 30 days after you complete site clearance

verification activities. Include information required under § 250.1743(b).(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. (1) Before you temporarily abandon or permanently plug a well or zone, Include information required under §§ 250.1712 and 250.1721.

(2) Within 30 days after you plug a well ................... Include information required under § 250.1717. (3) Before you install a subsea protective device ..... Refer to § 250.1722(a). (4) Within 30 days after you complete a protective

device trawl test. Include information required under § 250.1722(d). (5) Before you remove any casing stub or mud line

suspension equipment and any subsea protective

device. Refer to § 250.1723.

(6) Within 30 days after you complete site clearance

verification activities. 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 How must I permanently plug a**

**well?**

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



### P ERMANENT 

### W ELL 

### P LUGGING 

### R EQUIREMENTS

If you have . . . Then you must use . . .

(1) Zones in open hole, Cement plug(s) set from at least 100 feet below the bottom to 100 feet above the top of oil, gas, and fresh-water zones to isolate fluids in the strata. (2) Open hole below casing, (i) A cement plug, set by the displacement method, at least 100 feet above and below deepest casing shoe; (ii) A cement retainer with effective back-pressure control set 50 to 100 feet above the casing

shoe, and a cement plug that extends at least 100 feet below the casing shoe and at least 50 feet above the retainer; or (iii) A bridge plug set 50 feet to 100 feet above the shoe with 50 feet of cement on top of the

bridge plug, for expected or known lost circulation conditions. (3) A perforated zone that is currently open

and not previously squeezed or isolated, (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. (4) A casing stub where the stub end is within

the casing, (i) A cement plug set at least 100 feet above and below the stub end;


### 64589 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

P ERMANENT 

### W ELL 

### P LUGGING 

### R EQUIREMENTS

### —Continued

If you have . . . Then you must use . . .

(ii) A cement retainer or bridge plug set at least 50 to 100 feet above the stub end with at

least 50 feet of cement on top of the retainer or bridge plug; or (iii) A cement plug at least 200 feet long with the bottom of the plug set no more than 100

feet above the stub end. (5) A casing stub where the stub end is below

the casing, A plug as specified in paragraph (a)(1) or (a)(2) of this section, as applicable.

(6) An annular space that communicates with

open hole and extends to the mud line, 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. (7) A subsea well with unsealed annulus, A cutter to sever the casing, and you must set a stub plug as specified in paragraphs (a)(4) and (a)(5) of this section. (8) A well with casing, A cement surface plug at least 150 feet long set in the smallest casing that extends to the mud line with the top of the plug no more than 150 feet below the mud line. (9) Fluid left in the hole, A fluid in the intervals between the plugs that is dense enough to exert a hydrostatic pressure that is greater than the formation pressures in the intervals. (10) Permafrost areas, (i) A fluid to be left in the hole that has a freezing point below the temperature of the permafrost, and a treatment to inhibit corrosion; and (ii) Cement plugs designed to set before freezing and have a low heat of hydration.

(b) You must test the first plug below the surface plug and all plugs in lost circulation areas that are in open hole. The plug must pass one of the following tests to verify plug integrity:

(1) A pipe weight of at least 15,000 pounds on the plug; or

(2) A pump pressure of at least 1,000 pounds per square inch. Ensure that the pressure does not drop more than 10 percent in 15 minutes. The District Manager may require you to tests other plug(s).

**§ 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).

**§ 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; (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 alternaterequirements for subsea wells case-bycase; (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


### 64590 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

certification with your APM (Form BSEE–0124) required by § 250.1712.

**§ 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 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 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; (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 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) Well site, 300-foot-radius circle centered on the well location. (2) Subsea well site, 600-foot-radius circle centered on the well location. (3) Platform site, 1,320-foot-radius circle centered on the location of the platform. (4) Single-well caisson, well protector jacket, template, or manifold, 600-foot-radius circle centered on the structure locatio n.

(b) You must trawl 100 percent of the limits described in paragraph (a) of this

section in two directions.

(c) You must mark the area to be cleared as a hazard to navigation according to USCG requirements until you complete the site clearance procedures. (d) You must use a trawling vessel equipped with a calibrated navigational positioning system capable of providing position accuracy of ± 30 feet.

(e) You must use a trawling net that is representative of those used in the commercial fishing industry (one that has a net strength equal or greater than that provided by No. 18 twine). (f) You must ensure that you trawl no closer than 300 feet from a shipwreck, and 500 feet from a sensitive biological

feature.

(g) If you trawl near an active pipeline, you must meet the requirements in the following table:

For . . . You must trawl . . . And you must . . .

(1) Buried active pipelines, First contact the pipeline owner or operator todetermine the condition of the pipeline before trawling over the buried pipeline. (2) Unburied active pipelines that are 8 inches

in diameter or larger, no closer than 100 feet to the either side of the pipeline, Trawl parallel to the pipeline Do not trawl across the pipeline. (3) Unburied smaller diameter active pipelines

in the trawl area that have obstructions ( e.g., pipeline valves) present, no closer than 100 feet to either side of the pipeline, Trawl parallel to the pipeline. Do not trawl across the pipeline.

(4) Unburied active pipelines in the trawl area

that are smaller than 8 inches in diameter and have no obstructions present, parallel to the pipeline,

(h) You must ensure that any trawling
contractor you may use:

(1) Has no corporate or other financial ties to you; and (2) Has a valid commercial trawling

license for both the vessel and its captain. **§ 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), Use a sonar signal with a frequency of at

least 500 kHz. (b) A diver, ensure that the diver visually inspects 100 percent of the appropriate grid area listed in § 250.1741(a), Ensure that the diver uses a search pattern of concentric circles or parallel lines spaced no more than 10 feet apart.(c) An ROV (remotely operated vehicle), ensure that the ROV camera records videotape over 100 percent of the appropriate grid area listed in § 250.1741(a), Ensure that the ROV uses a pattern of concentric circles or parallel lines spaced no more than 10 feet apart.


### 64593 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

**§ 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?** 

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 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; (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 What is the goal of my SEMS program?** 

The goal of your SEMS program is to promote safety and environmental protection by ensuring all personnel aboard a facility are complying with the policies and procedures identified in your SEMS.

(a) To accomplish this goal, you must ensure that your SEMS program identifies, addresses, and manages safety, environmental hazards, and impacts during the design, construction, start-up, operation, inspection, and maintenance of all new and existing facilities, including mobile offshore drilling units (MODU) while under BSEE jurisdiction and Department of Interior (DOI) regulated pipelines.


### 64594 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

(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).

**§ 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. **§ 250.1904 Documents incorporated by**

**reference.**

The effect of incorporation by
reference of a document into the regulations in this part is that the incorporated document is a requirement. When a section in this part incorporates all of a document, you are responsible for complying with the provisions of that entire document, except to the extent that section provides otherwise. If any incorporated document uses the word ‘‘should’’, it means must for purposes of these regulations.

**§§ 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 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;


### 64595 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

floating production, storage and offloading facilities; tension-leg platforms; and spars) used for exploration, development, production, and transportation activities for oil, gas, or sulphur from areas leased in the OCS. Facilities also include DOI regulated pipelines. You must document and maintain current analyses for each operation covered by this section for the life of the operation at the facility. The analyses must be updated when an
internal audit is conducted to ensure
that it is consistent with the current operations on your facility. Hazards analysis requirements for simple and nearly identical facilities, such as well jackets and single well caissons, may be fulfilled by performing a single hazards analysis which you can apply to all such facilities after you verify that any site specific deviations are addressed in each of the elements of your SEMS

program.

(a) Hazards Analysis (facility level). For a hazards analysis (facility level), you must perform an initial hazards analysis on each facility on or before November 15, 2011. The hazards analysis must be appropriate to the complexity of the operation and must identify, evaluate, and manage the hazards involved in the operation.

(1) The hazards analysis must address the following:

(i) Hazards of the operation; (ii) Previous incidents related to the operation you are evaluating, including any incident in which you were issued an Incident of Noncompliance or a civil or criminal penalty;

(iii) Control technology applicable to the operation your hazards analysis is evaluating; and

(iv) A qualitative evaluation of the possible safety and health effects on employees, and potential impacts to the human and marine environments, which may result if the control technology fails.

(2) The hazards analysis must be performed by a person(s) with experience in the operations being
evaluated. These individuals also need to be experienced in the hazards analysis methodologies being employed.

(3) You should assure that the
recommendations in the hazards analysis are resolved and that the
resolution is documented.

(b) Job Safety Analysis (JSA). You must develop and implement a JSA for
OCS activities identified or discussed in your SEMS program.

(1) You must keep a copy of the most recent JSA (operations/task level) at the job site and it must be readily accessible to employees. (2) Your JSA must identify, analyze,
and record:

(i) The steps involved in performing a specific job;

(ii) the existing or potential safety and
health hazards associated with each step; and

(iii) the recommended action(s)/ procedure(s) that will eliminate or
reduce these hazards and the risk of a workplace injury or illness.

(3) The supervisor of the person in charge of the task must approve the JSA prior to the commencement of the work.

**§ 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.

**§ 250.1913 What criteria for operating procedures must my SEMS program meet?** 

(a) You must develop and implement written operating procedures that provide instructions for conducting safe and environmentally sound activities involved in each operation addressed in your SEMS program. These procedures must include the job title and reporting relationship of the person or persons responsible for each of the facility’s operating areas and address the following: (1) Initial startup; (2) Normal operations; (3) All emergency operations (including but not limited to medical evacuations, weather-related evacuations and emergency shutdown operations);

(4) Normal shutdown; (5) Startup following a turnaround, or after an emergency shutdown;

(6) Bypassing and flagging out-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.

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

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


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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 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, 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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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.

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

To learn from incidents and help prevent similar incidents, your SEMS program must establish procedures for investigation of all incidents with serious safety or environmental consequences and require investigation of incidents that are determined by facility management or BSEE to have possessed the potential for serious safety or environmental consequences. Incident investigations must be initiated as promptly as possible, with due regard for the necessity of securing the incident scene and protecting people and the environment. Incident investigations must be conducted by personnel knowledgeable in the process involved, investigation techniques, and other specialties that are relevant or

necessary.

(a) The investigation of an incident must address the following:

(1) The nature of the incident; (2) The factors (human or other) that
contributed to the initiation of the incident and its escalation/control; and

(3) Recommended changes identified as a result of the investigation.

(b) A corrective action program must be established based on the findings of the investigation in order to analyze
incidents for common root causes. The corrective action program must:

(1) Retain the findings of investigations for use in the next hazard analysis update or audit;

(2) Determine and document the response to each finding to ensure that corrective actions are completed; and

(3) Implement a system whereby conclusions of investigations are
distributed to similar facilities and appropriate personnel within their organization.

**§ 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 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.

**§ 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. (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 followingqualifications 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. **§ 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 OCS for scientific and/or research purposes. Geological, geophysical, and geochemical data and information gathered and analyzed are made available to the public for inspection and reproduction at the earliest practicable time. The term does not include commercial geological or geophysical exploration or research.

Geological exploration means exploration that uses geological and geochemical techniques ( e.g., coring and test drilling, well logging, and bottom sampling) to produce data and information on oil, gas, and sulphur resources in support of possible exploration and development activities. The term does not include geological
scientific research.

Geological information means geological or geochemical data that have been analyzed, processed, or interpreted.

Geophysical data means measurements that have not been processed or interpreted.

Geophysical exploration means exploration that utilizes geophysical techniques ( e.g., gravity, magnetic, electromagnetic, or seismic) to produce data and information on oil, gas, and sulphur resources in support of possible exploration and development activities. The term does not include geophysical
scientific research.

Geophysical information means geophysical data that have been processed or interpreted.

Governor means the Governor of a State or the person or entity lawfully designated to exercise the powers granted to a Governor pursuant to the

Act.

Human environment means the physical, social, and economic components, conditions, and factors which interactively determine the state, condition, and quality of living conditions, employment, and health of those affected, directly or indirectly, by activities occurring on the OCS.

Hydrocarbon occurrence means the direct or indirect detection during drilling operations of any liquid or gaseous hydrocarbons by examination of well cuttings, cores, gas detector readings, formation fluid tests, wireline logs, or by any other means. The term does not include background gas, minor accumulations of gas, or heavy oil residues on cuttings and cores.

Interpreted geological information means knowledge, often in the form of schematic cross sections, 3-dimensional representations, and maps, developed by determining the geological significance of geological data and analyzed and processed geologic
information. Interpreted geophysical information means knowledge, often in the form of seismic cross sections, 3-dimensional representations, and maps, developed by determining the geological significance of geophysical data and processed geophysical information.

Lease means an agreement which is
issued under section 8 or maintained
under section 6 of the Act and which authorizes exploration for, and development and production of, minerals or the area covered by that authorization, whichever is required by
the context.

Lessee means a person who has entered into, or is the BOEM approved assignee of, a lease with the United States to explore for, develop, and produce the leased minerals. The term
‘‘lessee’’ also includes an owner of operating rights.

Marine environment means the physical, atmospheric, and biological components, conditions, and factors that interactively determine the quality of the marine ecosystem in the coastal
zone and in the OCS.

Material remains mean physical evidence of human habitation, occupation, use, or activity, including the site, location, or context in which
such evidence is situated.

Minerals mean oil, gas, sulphur, geopressured-geothermal and associated resources, and all other minerals which are authorized by an Act of Congress to be produced from public lands as
defined in section 103 of the Federal Land Policy and Management Act of 1976 (43 U.S.C. 1702).

Notice means a written statement of intent to conduct geological or geophysical scientific research related to oil, gas, and sulphur in the OCS other than under a permit.

Oil, gas, and sulphur mean oil, gas, sulphur, geopressured-geothermal, and
associated resources.

Outer Continental Shelf (OCS) means all submerged lands lying seaward and
outside the area of lands beneath navigable waters as defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301), and of which the subsoil and seabed appertain to the United States and are subject to its jurisdiction and
control.

Permit means the contract or agreement, other than a lease, issued pursuant to this part, under which a person acquires the right to conduct on the OCS, in accordance with appropriate statutes, regulations, and stipulations:

(1) Geological exploration for mineral

resources;

(2) Geophysical exploration for mineral resources;


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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. 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 Authority and applicability of this part.** 

BSEE authorizes you to conduct exploration or scientific research activities under this part in accordance with the Act, the regulations in this part, orders of the Director/Regional Director, and other applicable statutes, regulations, and amendments.

(a) This part does not apply to G&G exploration conducted by or on behalf
of the lessee on a lease in the OCS. Refer to 30 CFR part 550 if you plan to conduct G&G activities related to oil, gas, or sulphur under terms of a lease.

(b) Federal agencies are exempt from the regulations in this part.

(c) G&G exploration or G&G scientific
research related to minerals other than oil, gas, and sulphur is covered by regulations at 30 CFR part 580.

**§§ 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; (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, 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 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. Data means facts and statistics or samples which have not been analyzed or processed.

Development means those activities which take place following discovery of oil or natural gas in paying quantities, including geophysical activity, drilling, platform construction, and operation of all onshore support facilities, and which are for the purpose of ultimately producing the oil and gas discovered.

Director means the Director of the Bureau of Safety and Environmental Enforcement (BSEE) of the U.S. Department of the Interior or a designee
of the Director.

Exploration means the process of searching for oil and natural gas, including:

(1) Geophysical surveys where magnetic, gravity, seismic, or other systems are used to detect or imply the presence of such oil or natural gas, and

(2) Any drilling, whether on or off known geological structures, including the drilling of a well in which a discovery of oil or natural gas in paying quantities is made and the drilling of any additional delineation well after such discovery which is needed to delineate any reservoir and to enable the lessee to determine whether to proceed with development and production.

Governor means the Governor of a State, or the person or entity designated by, or pursuant to, State law to exercise the powers granted to a Governor pursuant to the Act.

Information, when used without a qualifying adjective, includes analyzed geological information, processed geophysical information, interpreted geological information, and interpreted geophysical information.

Interpreted geological information means knowledge, often in the form of schematic cross sections and maps, developed by determining the geological significance of data and analyzed geological information.

Interpreted geophysical information means knowledge, often in the form of schematic cross sections and maps, developed by determining the geological significance of geophysical data and processed geophysical information.

Lease means any form of
authorization which is issued under
section 8 or maintained under section 6
of the Act and which authorizes exploration for, and development and production of, oil or natural gas, or the land covered by such authorization, whichever is required by the context.

Lessee means the party authorized by a lease, or an approved assignment thereof, to explore for and develop and produce the leased deposits in accordance with the regulations in 30 CFR part 550, including all parties holding such authority by or through
the lessee.

Outer Continental Shelf (OCS) means all submerged lands which lie seaward
and outside of the area of lands beneath navigable waters as defined in the Submerged Lands Act (67 Stat. 29) and
of which the subsoil and seabed appertain to the United States and are subject to its jurisdiction and control.

Permittee means the party authorized by a permit issued pursuant to 30 CFR parts 251 and 551 to conduct activities
on the OCS.

Processed geophysical information means data collected under a permit or a lease which have been processed. Processing involves changing the form of data so as to facilitate interpretation. Processsing operations may include, but are not limited to, applying corrections for known perturbing causes, rearranging or filtering data, and combining or transforming data
elements.

Production means those activities which take place after the successful completion of any means for the removal of oil or natural gas, including such removal, field operations, transfer of oil or natural gas to shore, operation monitoring, maintenance, and workover drilling.

Secretary means the Secretary of the Interior or a designee of the Secretary.

**§ 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 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 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.

**§ 252.7 Privileged and proprietary data and**

**information to be made available to affected**

**States.**

(a)(1) The Governor of any affected State may designate an appropriate State official to inspect, at a regional location which the Director shall designate, any privileged or proprietary data or information received by the Director regarding any activity in an area adjacent to such State, except that no such inspection shall take place prior to the sale of a lease covering the area in which such activity was conducted.

(2)(i) Except as provided for in 30 CFR 250.197, 30 CFR 550.197, and 30 CFR 551.14, no privileged or proprietary data
or information will be transmitted to any affected State unless the lessee who provided the privileged or proprietary data or information agrees in writing to
the transmittal of the data or
information. (ii) Except as provided for in 30 CFR 250.197, 30 CFR 550.197, and 30 CFR 551.14, no privileged or proprietary data
or information will be transmitted to any affected State unless the permittee and all persons to whom the permittee
has sold the data or information under promise of confidentiality agree in writing to the transmittal of the data or
information.

(3) Knowledge obtained by a State official who inspects data or information under paragraph (a)(1) or
who receives data or information under paragraph (a)(2) of this section shall be subject to the requirements and
limitations of the Freedom of Information Act (5 U.S.C. 552), the regulations contained in 43 CFR part 2 (Records and Testimony), the Act (92 Stat. 629), the regulations contained in 30 CFR parts 250 and 550 (Oil and Gas and Sulphur Operations in the Outer Continental Shelf), the regulations contained in 30 CFR parts 251 and 551 (Geological and Geophysical Explorations of the Outer Continental Shelf), and the regulations contained in 30 CFR parts 252 and 552 (Outer
Continental Shelf Oil and Gas Information Program).

(4) Prior to the transmittal of any privileged or proprietary data or information to any State, or the grant of
access to a State official to such data or information, the Secretary shall enter into a written agreement with the
Governor of the State in accordance with section 26(e) of the Act (43 U.S.C. 1352). In that agreement the State shall agree, as a condition precedent to receiving or being granted access to such data or information to: (i) Protect and maintain the confidentiality of privileged or proprietary data and
information in accordance with the laws and regulations listed in paragraph (a)(3) of this section;

(ii) Waive the defenses as set forth in paragraph (b)(2) of this section; and

(iii) Hold the United States harmless from any violations of the agreement to protect the confidentiality of privileged or proprietary data or information by the State or its employees or contractors.

(b)(1) Whenever any employee of the Federal Government or of any State
reveals in violation of the Act or of the provisions of the regulations implementing the Act, privileged or proprietary data or information obtained pursuant to the regulations in this chapter, the lessee or permittee who supplied such information to the Director or any other Federal official, and any person to whom such lessee or permittee has sold such data or information under the promise of confidentiality, may commence a civil action for damages in the appropriate
district court of the United States against the Federal Government or such State, as the case may be. Any Federal or State employee who is found guilty of failure to comply with any of the requirements of this section shall be subject to the penalties described in section 24 of the Act (43 U.S.C. 1350).

(2) In any action commenced against
the Federal Government or a State pursuant to paragraph (b)(1) of this section, the Federal Government or such State, as the case may be, may not raise as a defense any claim of sovereign immunity, or any claim that the employee who revealed the privileged or proprietary data or information
which is the basis of such suit was acting outside the scope of the person’s employment in revealing such data or
information.

(c) If the Director finds that any State cannot or does not comply with the conditions described in the agreement entered into pursuant to paragraph (a)(4) of this section, the Director shall
thereafter withhold transmittal and deny access for inspection of privileged or proprietary data or information to
such State until the Director finds that such State can and will comply with
those conditions.

**PART 253—[RESERVED]**

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

**LINE**

**Subpart A—General**

Sec. 254.1 Who must submit a spill-response plan? 254.2 When must I submit a response plan? 254.3 May I cover more than one facility in my response plan? 254.4 May I reference other documents in my response plan? 254.5 General response plan requirements.

254.6 Definitions. 254.7 How do I submit my response plan to

the BSEE? 254.8 May I appeal decisions under this part? 254.9 Authority for information collection.

**Subpart B—Oil-Spill Response Plans for**

**Outer Continental Shelf Facilities**

254.20 Purpose. 254.21 How must I format my response plan?

254.22 What information must I include in the ‘‘Introduction and plan contents’’

section?
254.23 What information must I include in the ‘‘Emergency response action plan’’

section?
254.24 What information must I include in the ‘‘Equipment inventory’’ appendix?


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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**

**§ 254.1 Who must submit a spill-response plan?** 

(a) If you are the owner or operator of an oil handling, storage, or transportation facility, and it is located seaward of the coast line, you must submit a spill-response plan to BSEE for approval. Your spill-response plan must demonstrate that you can respond quickly and effectively whenever oil is discharged from your facility. Refer to § 254.6 for the definitions of ‘‘oil,’’ ‘‘facility,’’ and ‘‘coast line’’ if you have any doubts about whether to submit a plan.

(b) You must maintain a current response plan for an abandoned facility until you physically remove or dismantle the facility or until the Regional Supervisor notifies you in writing that a plan is no longer required.

(c) Owners or operators of offshore pipelines carrying essentially dry gas do not need to submit a plan. You must, however, submit a plan for a pipeline
that carries:

(1) Oil; (2) Condensate that has been injected into the pipeline; or

(3) Gas and naturally occurring
condensate.

(d) If you are in doubt as to whether you must submit a plan for an offshore facility or pipeline, you should check with the Regional Supervisor.

(e) If your facility is located landward of the coast line, but you believe your facility is sufficiently similar to OCS facilities that it should be regulated by BSEE, you may contact the Regional Supervisor, offer to accept BSEE jurisdiction over your facility, and request that BSEE seek from the agency with jurisdiction over your facility a relinquishment of that jurisdiction.

**§ 254.2 When must I submit a response plan?** 

(a) You must submit, and BSEE must approve, a response plan that covers each facility located seaward of the coast line before you may use that facility. To continue operations, you must operate the facility in compliance with the plan.

(b) Despite the provisions of paragraph (a) of this section, you may operate your facility after you submit your plan while BSEE reviews it for approval. To operate a facility without an approved plan, you must certify in writing to the Regional Supervisor that you have the capability to respond, to the maximum extent practicable, to a worst case discharge or a substantial threat of such a discharge. The certification must show that you have ensured by contract, or other means approved by the Regional Supervisor, the availability of private personnel and equipment necessary to respond to the discharge. Verification from the organization(s) providing the personnel and equipment must accompany the certification. BSEE will not allow you to operate a facility for more than 2 years without an approved plan.

(c) If you have a plan that BSEE already approved, you are not required to immediately rewrite the plan to comply with this part. You must, however, submit the information this regulation requires when submitting your first plan revision (see § 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 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.

**§ 254.6 Definitions.**

For the purposes of this part:

Adverse weather conditions mean weather conditions found in the operating area that make it difficult for response equipment and personnel to clean up or remove spilled oil or hazardous substances. These include, but are not limited to: Fog, inhospitable water and air temperatures, wind, sea ice, current, and sea states. It does not refer to conditions such as a hurricane, under which it would be dangerous or impossible to respond to a spill.

Area Contingency Plan means an Area Contingency Plan prepared and published under section 311(j) of the
Federal Water Pollution Control Act (FWPCA).

Coast line means the line of ordinary low water along that portion of the coast which is in direct contact with the open sea and the line marking the seaward
limit of inland waters.

Discharge means any emission (other than natural seepage), intentional or unintentional, and includes, but is not limited to, spilling, leaking, pumping, pouring, emitting, emptying, or dumping.

District Manager means the BSEE officer with authority and responsibility for a district within a BSEE Region.

Facility means any structure, group of structures, equipment, or device (other than a vessel) which is used for one or more of the following purposes: Exploring for, drilling for, producing, storing, handling, transferring, processing, or transporting oil. The term excludes deep-water ports and their associated pipelines as defined by the Deepwater Port Act of 1974, but includes other pipelines used for one or more of these purposes. A mobile offshore drilling unit is classified as a facility when engaged in drilling or downhole operations.

Maximum extent practicable means within the limitations of available technology, as well as the physical limitations of personnel, when responding to a worst case discharge in
adverse weather conditions.

National Contingency Plan means the
National Oil and Hazardous Substances Pollution Contingency Plan prepared and published under section 311(d) of the FWPCA, (33 U.S.C. 1321(d)) or
revised under section 105 of the Comprehensive Environmental Response Compensation and Liability Act (42 U.S.C. 9605).

National Contingency Plan Product
Schedule means a schedule of dispersants and other chemical or biological products, maintained by the Environmental Protection Agency, that may be authorized for use on oil discharges in accordance with the procedures found at 40 CFR 300.910.

Oil means oil of any kind or in any form, including but not limited to petroleum, fuel oil, sludge, oil refuse,
and oil mixed with wastes other than dredged spoil. This also includes hydrocarbons produced at the wellhead in liquid form (includes distillates or condensate associated with produced natural gas), and condensate that has been separated from a gas prior to injection into a pipeline. It does not include petroleum, including crude oil or any fraction thereof, which is specifically listed or designated as a hazardous substance under paragraphs (A) through (F) of section 101(14) of the Comprehensive Environmental Response, Compensation, and Liability Act (42 U.S.C. 9601) and which is subject to the provisions of that Act. It
also does not include animal fats and oils and greases and fish and marine mammal oils, within the meaning of paragraph (2) of section 61(a) of title 13, United States Code, and oils of vegetable origin, including oils from the seeds, nuts, and kernels referred to in paragraph (1)(A) of that section.

Oil spill removal organization (OSRO) means an entity contracted by an owner or operator to provide spill-response equipment and/or manpower in the
event of an oil or hazardous substance spill.

Outer Continental Shelf means all submerged lands lying seaward and
outside of the area of lands beneath navigable waters as defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of which the subsoil and seabed appertain to the United States and are subject to its jurisdiction and
control.

Owner or operator means, in the case of an offshore facility, any person owning or operating such offshore facility. In the case of any abandoned offshore facility, it means the person who owned such facility immediately prior to such abandonment. Pipeline means pipe and any associated equipment, appurtenance, or building used or intended for use in the transportation of oil located seaward of the coast line, except those used for deep-water ports. Pipelines do not include vessels such as barges or shuttle tankers used to transport oil from
facilities located seaward of the coast
line.

Qualified individual means an English-speaking representative of an owner or operator, located in the United States, available on a 24-hour basis, with full authority to obligate funds, carry out removal actions, and communicate with the appropriate Federal officials and the persons providing personnel and equipment in removal operations.

Regional Response Plan means a 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 May I appeal decisions under this part?** 

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

**§ 254.9 Authority for information**

**collection.**

(a) The Office of Management and Budget (OMB) has approved the information collection requirements in this part under 44 U.S.C. 3501 et seq. OMB assigned the control number
1010–0091. The title of this information collection is ‘‘30 CFR part 254, Oil Spill Response Requirements for Facilities
Located Seaward of the Coast line.’’

(b) BSEE collects this information to ensure that the owner or operator of an offshore facility is prepared to respond to an oil spill. BSEE uses the information to verify compliance with
the mandates of the Oil Pollution Act of 1990 (OPA). The requirement to submit this information is mandatory. No confidential or proprietary information
is collected.

(c) An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB
control number.

(d) Send comments regarding any aspect of the collection of information under this part, including suggestions for reducing the burden, to the
Information Collection Clearance Officer, Bureau of Safety and Environmental Enforcement, 381 Elden Street, Herndon, VA 20170. **Subpart B—Oil-Spill Response Plans**
**for Outer Continental Shelf Facilities**

**§ 254.20 Purpose.**

This subpart describes therequirements for preparing spillresponse plans for facilities located on
the OCS.

**§ 254.21 How must I format my response plan?** 

(a) You must divide your response plan for OCS facilities into the sections specified in paragraph (b) of this section and explained in the other sections of this subpart. The plan must have an easily found marker identifying each section. You may use an alternate format if you include a cross-reference table to identify the location of required sections. You may use alternate contents if you can demonstrate to the Regional Supervisor that they provide for equal or greater levels of preparedness.

(b) Your plan must include: (1) Introduction and plan contents. (2) Emergency response action plan. (3) Appendices: (i) Equipment inventory. (ii) Contractual agreements. (iii) Worst case discharge scenario. (iv) Dispersant use plan. (v) In situ burning plan. (vi) Training and drills.

**§ 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 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 foruse 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 forinspecting and maintaining spillresponse equipment in accordance with
§ 254.43.

**§ 254.25 What information must I include in the ‘‘Contractual agreements’’ appendix?** 

Your ‘‘Contractual agreements’’ appendix must furnish proof of any contracts or membership agreementswith 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. **§ 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 (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.

**§ 254.30 When must I revise my response plan?** 

(a) You must review your response plan at least every 2 years and submit all resulting modifications to the Regional Supervisor. If this review does not result in modifications, you must inform the Regional Supervisor in writing that there are no changes.

(b) You must submit revisions to your plan for approval within 15 days
whenever:

(1) A change occurs which significantly reduces your response capabilities;

(2) A significant change occurs in the worst case discharge scenario or in the type of oil being handled, stored, or transported at the facility; (3) There is a change in the name(s) or capabilities of the oil spill removal organizations cited in the plan; or

(4) There is a significant change to the Area Contingency Plan(s).

(c) The Regional Supervisor may require that you resubmit your plan if the plan has become outdated or if
numerous revisions have made its use
difficult.

(d) The Regional Supervisor will periodically review the equipment
inventories of OSRO’s to ensure that sufficient spill removal equipment is
available to meet the cumulative needs of the owners and operators who cite these organizations in their plans.

(e) The Regional Supervisor may require you to revise your plan if significant inadequacies are indicated by:

(1) Periodic reviews (described in paragraph (d) of this section);

(2) Information obtained during drills or actual spill responses; or

(3) Other relevant information the Regional Supervisor obtained.

**Subpart C—Related Requirements for**
**Outer Continental Shelf Facilities**

**§ 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. (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 24-
hour basis. The exercise must test the ability of facility personnel to communicate pertinent information in a timely manner to the qualified
individual.

(4) A semiannual deployment exercise of any response equipment which the BSEE Regional Supervisor requires an owner or operator to maintain at the facility or on dedicated vessels. You must deploy and operate each type of this equipment at least once each year. Each type need not be deployed and operated at each exercise.

(c) During your exercises, you must
simulate conditions in the area of operations, including seasonal weather variations, to the extent practicable. The exercises must cover a range of scenarios over the 3-year exercise period, simulating responses to large continuous spills, spills of short duration and limited volume, and your worst case discharge scenario.

(d) BSEE will recognize and give credit for any documented exercise conducted that satisfies some part of the required triennial exercise. You will
receive this credit whether the owner or operator, an OSRO, or a Government


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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.** 

(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 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 mayrequire 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 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.

**§ 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. **§ 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. **§ 254.54 Spill prevention for facilities**

**located in State waters seaward of the coast**

**line.**

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

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

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

Sec.
256.0 [Reserved] 256.1 Purpose. 256.2–256.5 [Reserved]

256.7 Cross references.
256.8–256.12 [Reserved]

**Subpart B—Oil and Gas Leasing Program [Reserved]** 

**Subpart C—Reports From Federal Agencies [Reserved]** 

**Subpart D—Call for Information and Nominations [Reserved]** 

**Subpart E—Area and Identification and Tract Size [Reserved]** 

**Subpart F—Lease Sales [Reserved]**

**Subpart G—Issuance of Leases [Reserved]**

**Subpart H—Rentals and Royalties [Reserved]** 

**Subpart I—Bonding [Reserved]**

**Subpart J—Assignments, Transfers, and**

**Extensions**

256.62–256.68 [Reserved] 256.70 Extension of lease by drilling or well reworking operations. 256.71 Directional drilling. 256.72 Compensatory payments as production. 256.73 Effect of suspensions on lease term.

**Subpart K—Termination of Leases**

256.76 [Reserved]

256.77 Cancellation of leases.

**Subpart L—Section 6 Leases**

256.79 Effect of regulations on lease.
256.80 [Reserved]


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**Subpart M—Studies [Reserved]**

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

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

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

**§ 256.0 [Reserved]**

**§ 256.1 Purpose.**

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

**§§ 256.2–256.5 [Reserved]**

**§ 256.7 Cross references.**

(a) For Bureau of Safety and Environmental Enforcement (BSEE) regulations governing exploration, development and production on leases, see 30 CFR parts 250 and 270.

(b) For BSEE regulations governing the appeal of an order or decision issued under the regulations in this part, see 30 CFR part 290.

(c) For multiple use conflicts, see the Environmental Protection Agency listing of ocean dumping sites—40 CFR
part 228.

(d) For related National Oceanic and Atmospheric Administration programs

see:

(1) Marine sanctuary regulations, 15 CFR part 922;

(2) Fishermen’s Contingency Fund, 50 CFR part 296;

(3) Coastal Energy Impact Program, 15 CFR part 931;

(e) For Coast Guard regulations on the oil spill liability of vessels and operators, see 33 CFR parts 132, 135,
and 136.

(f) For Coast Guard regulations on port access routes, see 33 CFR part 164.

(g) For compliance with the National Environmental Policy Act, see 40 CFR parts 1500 through 1508.

(h) For Department of Transportation regulations on offshore pipeline facilities, see 49 CFR part 195.

(i) For Department of Defense regulations on military activities on offshore areas, see 32 CFR part 252. **§§ 256.8–256.12 [Reserved]**

**Subpart B—Oil and Gas Leasing Program [Reserved]** 

**Subpart C—Reports From Federal Agencies [Reserved]** 

**Subpart D—Call for Information and Nominations [Reserved]** 

**Subpart E—Area and Identification and Tract Size [Reserved]** 

**Subpart F—Lease Sales [Reserved]**

**Subpart H—Rentals and Royalties [Reserved]** 

**Subpart I—Bonding [Reserved]**

**Subpart J—Assignments, Transfers,**

**and Extensions**

§§ 256.62–256.68 [Reserved]

**§ 256.70 Extension of lease by drilling or well reworking operations.** 

The term of a lease shall be extended beyond the primary term so long as drilling or well reworking operations are approved by the Secretary according to

the conditions set forth in 30 CFR

250.180.

**§ 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. **§ 256.73 Effect of suspensions on lease**

**term.**

(a) A suspension may extend the term of a lease (see 30 CFR 250.171) with the extension being the length of time the suspension is in effect except as provided in paragraph (b) of this

section.

(b) A Directed Suspension does not extend the lease term when the Regional Supervisor directs a suspension because
of:

(1) Gross negligence; or (2) A willful violation of a provision of the lease or governing regulations.

(c) BSEE may issue suspensions for a period of up to 5 years per suspension. The Regional Supervisor will set the length of the suspension based on the
conditions of the individual case involved. BSEE may grant consecutive suspensions. For more information on suspension of operations or production refer to the section under the heading ‘‘Suspensions’’ in 30 CFR part 250, subpart A.

**Subpart K—Termination of Leases**

**§ 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


### 64613 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

(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**

**§ 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**

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

270.6 Process.
270.7 Remedies.

Authority: 43 U.S.C. 1863.

**§ 270.1 Purpose.**

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

**§ 270.2 Application of this part.**

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

**§ 270.3 Definitions.**

As used in this part, the following terms shall have the following meanings:

Contract means any business agreement or arrangement (in which the parties do not stand in the relationship of employer and employee) between a lessee and any person which creates an obligation to provide goods, services, facilities, or property.

Lessee means the party authorized by a lease, grant of right-of-way, or an approved assignment thereof to explore, develop, produce, or transport oil, gas,
or other minerals or materials in the OCS pursuant to the Act and this part.

Person means a person or company, including but not limited to, a corporation, partnership, association, joint stock venture, trust, mutual fund, or any receiver, trustee in bankruptcy, or other official acting in a similar capacity for such company.

Subcontract means any business agreement or arrangement (in which the parties do not stand in the relationship of employer and employee) between a lessee’s contractor and any person other than a lessee that is in any way related to the performance of any one or more

contracts.

**§ 270.4 Discrimination prohibited.**

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

**§ 270.5 Complaint.**

(a) Whenever any person believes that
he or she has been denied a contract or subcontract to which this part applies on the grounds of race, creed, color, national origin, or sex, such person may complain of such denial or withholding to the Regional Director of the OCS Region in which such action is alleged to have occurred. Any complaint filed under this part must be submitted in writing to the appropriate Regional Director not later than 180 days after the date of the alleged unlawful denial of a

contract or subcontract which is the basis of the complaint.

(b) The complaint referred to in paragraph (a) of this section shall be accompanied by such evidence as may be available to a person and which is relevant to the complaint including

affidavits and other documents.

(c) Whenever any person files a complaint under this part, the Regional Director with whom such complaint is filed shall give written notice of such filing to all persons cited in the complaint no later than 10 days after receipt of such complaint. Such notice shall include a statement describing the alleged incident of discrimination, including the date and the names of persons involved in it.

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

**Subpart A—[Reserved]**

**Subpart B—[Reserved]**

**Subpart C—Obligations Under This Part**

Interrupted Activities

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

**Subpart D—[Reserved]**

**Subpart E—[Reserved]**

Authority: 43 U.S.C. 1334.

**Subpart C—Obligations Under This**

**Part**

Interrupted Activities

**§§ 280.20–280.24 [Reserved]**

**§ 280.25 When may BSEE require me to stop activities under this part?** 

(a) We may temporarily stop prospecting or scientific research activities under a permit when the Regional Director determines that:

(1) Activities pose a threat of serious, irreparable, or immediate harm. This includes damage to life (including fish and other aquatic life), property, and any minerals (in areas leased or not leased), to the marine, coastal, or human environment, or to an archaeological

resource;

(2) You failed to comply with any applicable law, regulation, order or provision of the permit. This would include our required submission of reports, well records or logs, and G&G
data and information within the time specified; or

(3) Stopping the activities is in the interest of National security or defense.

(b) The Regional Director will advise you either orally or in writing of the procedures to temporarily stop
activities. We will confirm an oral notification in writing and deliver all written notifications by courier or certified/registered mail. You must stop all activities under a permit as soon as you receive an oral or written
notification.

**§ 280.26 When may I resume activities?**

The Regional Director will advise you when you may start your permit activities again. **§ 280.27 When may BSEE cancel my permit?** 

The Regional Director may cancel a permit at any time.

(a) If we cancel your permit, the Regional Director will advise you by certified or registered mail 30 days
before the cancellation date and will
state the reason.

(b) After we cancel your permit, you are still responsible for proper abandonment of any drill site according to the requirements of 30 CFR 251.7(b)(8). You must comply with all other obligations specified in this part or in the permit.

**§ 280.28 May I relinquish my permit?**

(a) You may relinquish your permit at any time by advising the Regional Director by certified or registered mail 30 days in advance.

(b) After you relinquish your permit, you are still responsible for proper abandonment of any drill sites according to the requirements of 30 CFR 251.7(b)(8). You must also comply with all other obligations specified in this part or in the permit.

**Subpart D—[Reserved]**

**Subpart E—[Reserved]**

**PART 281—[RESERVED]**

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

**Subpart A—General**

Sec. 282.0 Authority for information collection. 282.1 Purpose and authority. 282.2 Scope.
282.3 Definitions. 282.4 [Reserved]

282.5 Disclosure of data and information to the public.

282.6 Disclosure of data and information to an adjacent State. 282.7 Jurisdictional controversies.

**Subpart B—Jurisdiction and Responsibilities of Director** 

282.10 Jurisdiction and responsibilities of

Director. 282.11 Director’s authority. 282.12 Director’s responsibilities. 282.13 Suspension of production or other operations. 282.14 Noncompliance, remedies, and penalties. 282.15 [Reserved]

**Subpart C—Obligations and Responsibilities of Lessees** 

282.20 [Reserved] 282.21 Plans, general. 282.22—282.26 [Reserved] 282.27 Conduct of operations. 282.28 Environmental protection measures. 282.29 [Reserved] 282.30 [Reserved] 282.31 Suspension of production or other operations.

**Subpart D—Payments**

282.40 [Reserved] 282.41 Method of royalty calculation 282.42 [Reserved]

**Subpart E—Appeals**

282.50 Appeals.

Authority: 43 U.S.C. 1334.

**Subpart A—General**

**§ 282.0 Authority for information**

**collection.**

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

**§ 282.1 Purpose and authority.**

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

(b) Subject to the supervisory authority of the Secretary, and unless otherwise specified, the regulations in this part shall be administered by the
Director of BSEE.

**§ 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:


### 64615 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

Act means the OCS Lands Act, as amended (43 U.S.C. 1331 et seq. ).

Adjacent State means with respect to any activity proposed, conducted, or approved under this part, any coastal

State:

(1) That is, or is proposed to be, receiving for processing, refining, or transshipment OCS mineral resources commercially recovered from the seabed;

(2) That is used, or is scheduled to be used, as a support base for prospecting, exploration, testing, or mining activities;

or (3) In which there is a reasonable probability of significant effect on land or water uses from such activity.

Contingency Plan means a plan for action to be taken in emergency

situations.

Data means geological and geophysical (G&G) facts and statistics or samples which have not been analyzed, processed, or interpreted.

Development means those activities which take place following the discovery of minerals in paying quantities including geophysical activities, drilling, construction of offshore facilities, and operation of all onshore support facilities, which are for the purpose of ultimately producing the
minerals discovered.

Director means the Director of BSEE of the U.S. Department of the Interior or
an official authorized to act on the
Director’s behalf.

Exploration means the process of searching for minerals on a lease including:

(1) Geophysical surveys where magnetic, gravity, seismic, or other systems are used to detect or imply the presence of minerals;

(2) Any drilling including the drilling of a borehole in which the discovery of a mineral other than oil, gas, or sulphur is made and the drilling of any
additional boreholes needed to delineate any mineral deposits; and

(3) The taking of sample portions of a mineral deposit to enable the lessee to determine whether to proceed with development and production.

Geological sample means a collected portion of the seabed, the subseabed, or the overylying waters (when obtained for geochemical analysis) acquired while conducting postlease mining

activities.

Governor means the Governor of a State or the person or entity designated by, or pursuant to, State law to exercise the power granted to a Governor.

Information means G&G data that have been analyzed, processed, or interpreted.

Lease means one of the following, whichever is required by the context: Any form of authorization which is
issued under section 8 or maintained
under section 6 of the Acts and which authorizes exploration for, and development and production of, specific minerals; or the area covered by that
authorization.

Lessee means the person authorized by a lease, or an approved assignment thereof, to explore for and develop and produce the leased deposits in accordance with the regulations in this chapter. The term includes all parties holding that authority by or through the
lessee.

Major Federal action means any action or proposal by the Secretary which is subject to the provisions of section 102(2)(C) of the National Environmental Policy Act (NEPA) (i.e., an action which will have a significant impact on the quality of the human environment requiring preparation of an Environmental Impact Statement (EIS) pursuant to section 102(2)(C) of NEPA).

Marine environment means the physical, atmospheric, and biological components, conditions, and factors which interactively determine the productivity, state, condition, and quality of the marine ecosystem, including the waters of the high seas, the contiguous zone, transitional and intertidal areas, salt marshes, and
wetlands within the coastal zone and on
the OCS.

Minerals include oil, gas, sulphur, geopressured-geothermal and associated resources, and all other minerals which are authorized by an Act of Congress to be produced from ‘‘public lands’’ as
defined in section 103 of the Federal Land Policy and Management Act of

1976.

OCS mineral means any mineral deposit or accretion found on or below
the surface of the seabed but does not include oil, gas, or sulphur; salt or sand and gravel intended for use in association with the development of oil, gas, or sulphur; or source materials essential to production of fissionable
materials which are reserved to the United States pursuant to section 12(e)
of the Act.

Operator means the individual, partnership, firm, or corporation having control or management of operations on the lease or a portion thereof. The operator may be a lessee, designated agent of the lessee, or holder of rights under an approved operating agreement.

Outer Continental Shelf means all submerged lands lying seaward and
outside of the area of lands beneath navigable waters as defined in section 2 of Submerged Lands Act (43 U.S.C. 1301) and of which the subsoil and seabed appertain to the United States and are subject to its jurisdiction and
control.

Person means a citizen or national of the United States; an alien lawfully admitted for permanent residency in the
United States as defined in 8 U.S.C. 1101(a)(20); a private, public, or municipal corporation organized under the laws of the United States or of any State or territory thereof; an association of such citizens, nationals, resident aliens or private, public, or municipal corporations, States, or political subdivisions of States; or anyone operating in a manner provided for by treaty or other applicable international agreements. The term does not include Federal Agencies.

Secretary means the Secretary of the
Interior or an official authorized to act on the Secretary’s behalf.

Testing means removing bulk samples for processing tests and feasibility studies and/or the testing of mining equipment to obtain information needed to develop a detailed Mining Plan.

**§ 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


### 64616 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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.

**§ 282.7 Jurisdictional controversies.**

In the event of a controversy between

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

issuance or nonissuance of new leases pending settlement of the controversy. **Subpart B—Jurisdiction and Responsibilities of Director** 

**§ 282.10 Jurisdiction and responsibilities**

**of Director.**

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

**§ 282.11 Director’s authority.**

(a)–(c) [Reserved] (d)(1) The Director may approve the
consolidation of two or more OCS mineral leases or portions of two or more OCS mineral leases into a single mining unit requested by lessees, or the Director may require such consolidation when the operation of those leases or portions of leases as a single mining
unit is in the interest of conservation of
the natural resources of the OCS or the prevention of waste. A mining unit may also include all or portions of one or
more OCS mineral leases with all or portions of one or more adjacent State
leases for minerals in a common orebody. A single unit operator shall be responsible for submission of required Delineation, Testing, and Mining Plans covering OCS mineral operations for an approved mining unit.

(2) Operations such as exploration, testing, and mining activities conducted in accordance with an approved plan on any lease or portion of a lease which is subject to an approved mining unit shall be considered operations on each of the leases that is made subject to the approved mining unit.

(3) Minimum royalty paid pursuant to a Federal lease, which is subject to an approved mining unit, is creditable against the production royalties allocated to that Federal lease during the lease year for which the minimum royalty is paid.

(4) Any OCS minerals produced from
State and Federal leases which are subject to an approved mining unit shall be accounted for separately unless a method of allocating production
between State and Federal leases has been approved by the Director and the appropriate State official.

**§ 282.12 Director’s responsibilities.**

(a) The Director is responsible for the regulation of activities to assure that all operations conducted under a lease or right of use and easement are conducted in a manner that protects the environment and promotes orderly development of OCS mineral resources. Those activities are to be designed to prevent serious harm or damage to, or waste of, any natural resource (including OCS mineral deposits and oil, gas, and sulphur resources in areas leased or not leased), any life (including fish and other aquatic life), property, or the marine, coastal, or human

environment.

(b)–(d) [Reserved] (e) The Director shall assure that a scheduled onsite compliance inspection of each facility which is subject to regulations in this part is conducted at least once a year. The inspection shall
be to determine that the lessee is in compliance with the requirements of the law; provisions of the lease; the approved Delineation, Testing, or Mining Plan; and the regulations in this part. Additional unscheduled onsite inspections shall be conducted without
advance notice to the lessee to assure compliance with the provisions of applicable law; the lease; the approved Delineation, Testing, or Mining Plan; and the regulations in this part.

(f)(1) The Director shall, after completion of the technical and environmental evaluations, approve, disapprove, or require modification of the lessee’s requests, applications, plans, and notices submitted pursuant to the provisions of this part; issue orders to govern lease operations; and require compliance with applicable provisions of the law, the regulations, the lease, and the approved Delineation, Testing, or Mining Plans. The Director may give oral orders or approvals whenever prior approval is required
before the commencement of an operation or activity. Oral orders or approvals given in response to a written request shall be confirmed in writing within 3 working days after issuance of the order or granting of the oral approval.

(2) The Director shall, after completion of the technical and environmental evaluations, approve, disapprove, or require modification, as appropriate, of the design plan, fabrication plan, and installation plan for platforms, artificial islands, and
other installations and devices permanently or temporarily attached to the seabed. The approval, disapproval,


### 64617 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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.

**§ 282.13 Suspension of production or other operations.** 

(a) The Director may direct the suspension or temporary prohibition of production or any other operation or activity on all or any part of a lease
when it has been determined that such suspension or temporary prohibition is
in the National interest to:

(1) Facilitate proper development of a lease including a reasonable time to develop a mine and construct necessary support facilities, or

(2) Allow for the construction or negotiation for use of transportation
facilities.

(b) The Director may also direct or, at the request of the lessee, approve a suspension or temporary prohibition of production or any other operation or activity, if:

(1) The lessee failed to comply with a provision of applicable law, regulation, order, or the lease;

(2) There is a threat of serious, irreparable, or immediate harm or damage to life (including fish and other aquatic life), property, any mineral deposit, or the marine, coastal, or human environment;

(3) The suspension or temporary prohibition is in the interest of National security or defense;

(4) The suspension or temporary prohibition is necessary for the
initiation and conduct of an
environmental evaluation to define mitigation measures to avoid or
minimize adverse environmental impacts.

(5) The suspension or temporary prohibition is necessary to facilitate the installation of equipment necessary for safety of operations and protection of the environment;

(6) The suspension or temporary prohibition is necessary to allow for undue delays encountered by the lessee in obtaining required permits or consents, including administrative or judicial challenges or appeals; (7) The Director determines that continued operations would result in premature abandonment of a producing mine, resulting in the loss of otherwise recoverable OCS minerals;

(8) The Director determines that the lessee cannot successfully operate a producing mine due to market conditions that are either temporary in nature or require temporary shutdown
and reinvestment in order for the lessee to adapt to the conditions; or

(9) The suspension or temporary prohibition is necessary to comply with judicial decrees prohibiting production or any other operation or activity, or the permitting of those activities, effective the date set by the court for that prohibition.

(c) When the Director orders or approves a suspension or a temporary prohibition of operation or activity including production on all of a lease pursuant to paragraph (a) or (b) of this section, the term of the lease shall be extended for a period of time equal to the period of time that the suspension or temporary prohibition is in effect, except that no lease shall be so extended when the suspension or temporary prohibition is the result of the lessee’s gross negligence or willful violation of a provision of the lease or governing regulations.

(d) The Director may, at any time within the period prescribed for a suspension or temporary prohibition issued pursuant to paragraph (b)(2) of this section, require the lessee to submit a Delineation, Testing, or Mining Plan for approval in accordance with the requirements for the approval of such plans in this part.

(e)(1) When the Director orders or issues a suspension or a temporary prohibition pursuant to paragraph (b)(2) of this section, the Director may require the lessee to conduct site-specific studies to identify and evaluate the cause(s) of the hazard(s) generating the suspension or temporary prohibition, the potential for damage from the hazard(s), and the measures available for mitigating the hazard(s). The nature, scope, and content of any study shall be subject to approval by the Director. The lessee shall furnish copies and all results of any such study to the Director. The cost of the study shall be borne by the lessee unless the Director arranges for the cost of the study to be borne by a party other than the lessee. The Director shall make results of any such study available to interested parties and to the public as soon as practicable after the completion of the study and
submission of the results thereof.

(2) When the Director determines that measures are necessary, on the basis of the results of the studies conducted in accordance with paragraph (e)(1) of this
section and other information available to and identified by the Director, the lessee shall be required to take appropriate measures to mitigate, avoid, or minimize the damage or potential damage on which the suspension or temporary prohibition is based. When deemed appropriate by the Director, the
lessee shall submit a revised Delineation, Testing, or Mining Plan to incorporate the mitigation measures required by the Director. In choosing between alternative mitigation measures, the Director shall balance the cost of the required measures against the reduction or potential reduction in damage or threat of damage or harm to life (including fish and other aquatic life), to property, to any mineral deposits (in areas leased or not leased), to the National security or defense, or to the marine, coastal, or human

environment.

(f)(1) If under the provisions of paragraphs (b)(2), (3), and (4) of this section, the Director, with respect to any lease, directs the suspension of production or other operations on the entire leasehold, no payment of rental or minimum royalty shall be due for or during the period of the directed suspension and the time for the lessee specify royalty free period of a period of reduced royalty pursuant to 30 CFR 581.28(b) will be extended for the period of directed suspension. If under the provisions of paragraphs (b)(2), (3), and (4) of this section the Director, with respect to a lease on which there has been no production, directs the suspension of operations on the entire leasehold, no payment of rental shall be due during the period of the directed suspension.

(2) If under the provisions of this section, the Director grants the request of a lessee for a suspension of production or other operations, the lessee’s obligations to pay rental, minimum royalty, or royalty shall continue to apply during the period of the approved suspension, unless the Director’s approval of the lessee’s request for suspension authorizes the payment of a lesser amount during the period of approved suspension. If under the provision of this section, the Director grants a lessee’s request for a suspension of production or other operations for a lease which includes provisions for a time period which the lessee may specify during which production from the leasehold would be royalty free or subject to a reduced royalty obligation pursuant to 30 CFR 581.28(b), the time during which production from a leasehold may be


### 64618 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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.

**§ 282.14 Noncompliance, remedies, and penalties.** 

(a)(1) If the Director determines that a lessee has failed to comply with applicable provisions of law; the regulations in this part; other applicable regulations; the lease; the approved Delineation, Testing, or Mining Plan; or the Director’s orders or instructions, and
the Director determines that such noncompliance poses a threat of immediate, serious, or irreparable damage to the environment, the mine or the deposit being mined, or other valuable mineral deposits or other resources, the Director shall order the
lessee to take immediate and appropriate remedial action to alleviate the threat. Any oral orders shall be followed up by service of a notice of noncompliance upon the lessee by delivery in person to the lessee or agent, or by certified or registered mail
addressed to the lessee at the last known
address.

(2) If the Director determines that the lessee has failed to comply with applicable provisions of law; the regulations in this part; other applicable regulations; the lease; the requirements of an approved Delineation, Testing, or Mining Plan; or the Director’s orders or instructions, and such noncompliance does not pose a threat of immediate, serious, or irreparable damage to the environment, the mine or the deposit being mined, or other valuable mineral deposits or other resources, the Director shall serve a notice of noncompliance upon the lessee by delivery in person to the lessee or agent or by certified or registered mail addressed to the lessee
at the last known address.

(b) A notice of noncompliance shall specify in what respect(s) the lessee has failed to comply with the provisions of applicable law; regulations; the lease; the requirements of an approved Delineation, Testing, or Mining Plan; or the Director’s orders or instructions, and shall specify the action(s) which must be taken to correct the noncompliance
and the time limits within which such
action must be taken.

(c) Failure of a lessee to take the actions specified in the notice of noncompliance within the time limit specified shall be grounds for a suspension of operations and other appropriate actions, including but not
limited to the assessment of a civil penalty of up to $10,000 per day for
each violation that is not corrected within the time period specified (43 U.S.C. 1350(b)).

(d) Whenever the Director determines that a violation of or failure to comply with any provision of the Act; or any provision of a lease, license, or permit issued pursuant to the Act; or any provision of any regulation promulgated under the Act probably occurred and that such apparent violation continued beyond notice of the violation and the expiration of the reasonable time period allowed for corrective action, the Director shall follow the procedures concerning remedies and penalties in subpart N, Remedies and Penalties, of 30 CFR part 250 to determine and assess an appropriate penalty.

(e) The remedies and penalties prescribed in this section shall be concurrent and cumulative, and the exercise of one shall not preclude the exercise of the other. Further, the remedies and penalties prescribed in this section shall be in addition to any other remedies and penalties afforded by any other law or regulation (43 U.S.C. 1350(e)).

**§ 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 [Reserved]**

**§ 282.27 Conduct of operations.**

(a) The lessee shall conduct all exploration, testing, development, and production activities and other operations in a safe and workmanlike manner and shall maintain equipment
in a manner which assures the protection of the lease and its improvements, the health and safety of all persons, and the conservation of property, and the environment.

(b) Nothing in this part shall preclude
the use of new or alternative technologies, techniques, procedures, equipment, or activities, other than those prescribed in the regulations of this part, if such other technologies, techniques, procedures, equipment, or activities afford a degree of protection, safety, and performance equal to or
better than that intended to be achieved by the regulations of this part, provided the lessee obtains the written approval of the Director prior to the use of such new or alternative technologies, techniques, procedures, equipment, or

activities.

(c) The lessee shall immediately notify the Director when there is a death or serious injury; fire, explosion, or
other hazardous event which threatens damage to life, a mineral deposit, or equipment; spills of oil, chemical reagents, or other liquid pollutants which could cause pollution; or damage to aquatic life or the environment associated with operations on the lease. As soon as practical, the lessee shall file a detailed report on the event and action(s) taken to control the situation and to mitigate any further damage.

(d)(1) Lessees shall provide means, at all reasonable hours either day or night, for the Director to inspect or investigate the conditions of the operation and to determine whether applicable regulations; terms and conditions of the lease; and the requirements of the approved Delineation, Testing, or Mining Plan are being met.

(2) A lessee shall, on request by the Director, furnish food, quarters, and transportation for BSEE representatives to inspect its facilities. Upon request, the lessee will be reimbursed by the
United States for the actual costs which it incurs as a result of its providing food, quarters, and transportation for a BSEE representative’s stay of more than 10 hours. Request for reimbursement must be submitted within 60 days following the cost being incurred.

(e) Mining and processing vessels, platforms, structures, artificial islands, and mobile drilling units which have helicopter landing facilities shall be identified with at least one sign using letters and figures not less than 12 inches in height. Signs for structures without helicopter landing facilities shall be identified with at least one sign using letters and figures not less than 3 inches in height. Signs shall be affixed
at a location that is visible to


### 64619 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

approaching traffic and shall contain the following information which may be
abbreviated:

(1) Name of the lease operator; (2) The area designation based on Official OCS Protraction Diagrams;

(3) The block number in which the facility is located; and

(4) Vessel, platform, structure, or rig

name.

(f)(1) Drilling. (i) When drilling on lands valuable or potentially valuable for oil and gas or geopressured or geothermal resources, drilling equipment shall be equipped with blowout prevention and control devices acceptable to the Director before penetrating more than 500 feet unless a different depth is specified in advance by the Director.

(ii) In cases where the Director
determines that there is sufficient likelihood of encountering pressurized hydrocarbons, the Director may require that the lessee comply with all or portions of the requirements in part 250, subpart D, of this title.

(iii) Before drilling any hole which may penetrate an aquifer, the lessee shall follow the procedures included in the approved plan for the penetration and isolation of the aquifer during the drilling operation, during use of the hole, and for subsequent abandonment
of the hole.

(iv) Cuttings from holes drilled on the lease shall be disposed of and
monitored in accordance with the approved plan.

(v) The use of muds in drilling holes on the lease and their subsequent disposition shall be according to the approved plan.

(2) All drill holes which are susceptible to logging shall be logged, and the lessee shall prepare a detailed lithologic log of each drill hole. Drill holes which are drilled deeper than 500
feet shall be drilled in a manner which permits logging. Copies of logs of cores and cuttings and all in-hole surveys such as electronic logs, gamma ray logs, neutron density logs, and sonic logs shall be provided to the Director.

(3) Drill holes for exploration, testing, development, or production shall be properly plugged and abandoned to the
satisfaction of the Director in accordance with the approved plan and in such a manner as to protect the surface and not endanger any operation; any freshwater aquifer; or deposit of oil, gas, or other mineral substance.

(g) The use of explosives on the lease
shall be in accordance with the approved plan.

(h)(1) Any equipment placed on the seabed shall be designed to allow its recovery and removal upon
abandonment of leasehold activities.

(2) Disposal of equipment, cables, chains, containers, or other materials into the ocean is prohibited.

(3) Materials, equipment, tools, containers, and other items used on the OCS which are of such shape or configuration that they are likely to snag or damage fishing devices shall be
handled and marked as follows:

(i) All loose materials, small tools, and other small objects shall be kept in a suitable storage area or a marked
container when not in use or in a marked container before transport over
OCS waters;

(ii) All cable, chain, or wire segments shall be recovered after use and securely stored;

(iii) Skid-mounted equipment, portable containers, spools or reels, and
drums shall be marked with the owner’s name prior to use or transport over OCS waters; and

(iv) All markings must clearly identify the owner and must be durable enough
to resist the effects of the environmental conditions to which they are exposed.

(4) Any equipment or material described in paragraphs (h)(2), (h)(3)(ii), and (iii) of this section that is lost overboard shall be recorded on the daily operations report of the facility and reported to the Director and to the U.S.
Coast Guard.

(i) Any bulk sampling or testing that is necessary to be conducted prior to submission of a Mining Plan shall be in accordance with an approved Testing Plan. The sale of any OCS minerals acquired under an approved Testing Plan shall be subject to the payment of the royalty specified in the lease to the
United States.

(j) Installations and structures: (1) The lessee shall design, fabricate, install, use, inspect, and maintain all installations and structures, including platforms on the OCS, to assure the structural integrity of all installations
and structures for the safe conduct of exploration, testing, mining, and processing activities considering the specific environmental conditions at the
location of the installation or structure.

(2) All fixed or bottom-founded platforms or other structures, e.g., artificial islands shall be designed, fabricated, installed, inspected, and
maintained in accordance with the provisions of 30 CFR part 250, subpart

I. (k) The lessee shall not produce any
OCS mineral until the method of measurement and the procedures for product valuation have been instituted in accordance with the approved Testing or Mining Plan. The lessee shall enter the weight or quantity and quality of each mineral produced in accordance
with 30 CFR 582.29.

(l) The lessee shall conduct OCS mineral processing operations in accordance with the approved Testing or Mining Plan and use due diligence in the reduction, concentration, or separation of mineral substances by mechanical or chemical processes, by evaporation, or other means, so that the percentage of concentrates or other
mineral substances are recovered in accordance with the practices approved in the Testing or Mining Plan.

(m) No material shall be discharged or disposed of except in accordance with the approved disposal practice and procedures contained in the approved Delineation, Testing, or Mining Plan.

**§ 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:


### 64620 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

(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]**

**§ 282.31 Suspension of production or other operations.** 

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

**Subpart D—Payments**

**§ 282.40 [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.

**PART 285—[RESERVED]**

**SUBCHAPTER C—APPEALS**

**PART 290—APPEAL PROCEDURES**

**Subpart A—Bureau of Safety and Environmental Enforcement Appeal** 

**Procedures**

Sec. 290.1 What is the purpose of this subpart? 290.2 Who may appeal? 290.3 What is the time limit for filing an appeal? 290.4 How do I file an appeal? 290.5 Can I obtain an extension for filing my Notice of Appeal? 290.6 Are informal resolutions permitted? 290.7 Do I have to comply with the decision or order while my appeal is pending? 290.8 How do I exhaust my administrative

remedies?

**Subpart B [Reserved]**

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

1331.

**Subpart A—Bureau of Safety and Environmental Enforcement Appeal** 

**Procedures**

**§ 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 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. (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.

**§ 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: (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 What definitions apply to this part?** 

As used in this part: Accessory means a platform, a major subsea manifold, or similar subsea structure attached to a right-of-way (ROW) pipeline to support pump stations, compressors, manifolds, etc. The site used for an accessory is part of the pipeline ROW grant.

Appurtenance means equipment, device, apparatus, or other object attached to a horizontal component or riser. Examples include anodes, valves, flanges, fittings, umbilicals, subsea manifolds, templates, pipeline end modules (PLEMs), pipeline end terminals (PLETs), anode sleds, other sleds, and jumpers (other than jumpers connecting subsea wells to manifolds).

FERC pipeline means any pipeline within the jurisdiction of the Federal Energy Regulatory Commission (FERC) under the Natural Gas Act, 15 U.S.C. 717–717z, or the Interstate Commerce Act, 42 U.S.C. 7172(a) and (b).

Grantee means any person to whom BSEE has issued an oil or gas pipeline permit, license, easement, right-of-way, or other grant of authority for transportation on or across the OCS under 30 CFR part 250, subpart J, or 43 U.S.C. 1337(p), and any person who has an assignment of a permit, license, easement, right-of-way or other grant of authority, or who has an assignment of any rights subject to any of those grants of authority under 30 CFR part 250, subpart J or 43 U.S.C. 1337(p).

IBLA means the Interior Board of Land Appeals.

OCSLA pipeline means any oil or gas pipeline for which BSEE has issued a permit, license, easement, right-of-way, or other grant of authority.

Outer Continental Shelf means all submerged lands lying seaward and
outside of the area of lands beneath navigable waters as defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of which the subsoil and seabed appertain to the United States and are subject to its jurisdiction and
control.

Party means any person who files a complaint, any person who files an answer, and BSEE.

Person means an individual, corporation, government entity, partnership, association (including a trust or limited liability company), consortium, or joint venture (when established as a separate entity).

Pipeline is the piping, risers, accessories and appurtenances installed for transportation of oil and gas.

Serve means personally delivering a document to a person, or sending a document by U.S. mail or private delivery services that provide proof of delivery (such as return receipt requested) to a person.

Shipper means a person who
contracts or wants to contract with a grantee or transporter to transport oil or gas through the grantee’s or transporter’s pipeline.

Transportation means, for purposes of this part only, the movement of oil or gas through an OCSLA pipeline.

Transporter means, for purposes of this part only, any person who owns or operates an OCSLA oil or gas pipeline.

**§ 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.


### 64622 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

**§ 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.

**§ 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, includingpractical, operational, or other nonfinancial impacts; (d) Estimate any financial impact or burden;

(e) State the specific relief or remedy requested; and

(f) Include all documents that support the facts in your complaint including, but not limited to, contracts and any affidavits that may be necessary to support particular factual allegations.

**§ 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 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 How do I pay the processing**

**fee?**

(a) You must pay the processing fee electronically through Pay.Gov. The Pay.Gov Web site may be accessed through links on the BSEE Offshore Web

site at: http://www.bsee.gov/offshore/ homepage (on drop-down topic list) or directly through Pay.Gov at: https:// www.pay.gov/paygov/.

(b) You must include with the
payment:

(1) Your taxpayer identification number;

(2) Your payor identification number, if applicable; and

(3) The complaint caption, or any other applicable identification of the complaint you are filing.

**§ 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


### 64623 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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.

**§ 291.111 How does BSEE treat the confidential information I provide?** 

(a) Any person who provides documents under this part in response to a request by BSEE to inform a decision on whether open access or nondiscriminatory access was denied may claim that some or all of the information contained in a particular document is confidential. If you claim confidential treatment, then when you provide the document to BSEE you

must:

(1) Provide a complete unredacted copy of the document and indicate on that copy that you are making a request
for confidential treatment for some or all
of the information in the document.

(2) Provide a statement specifying the specific statutory justification for
nondisclosure of the information for which you claim confidential treatment. General claims of confidentiality are not
sufficient. You must furnish sufficient
information for BSEE to make an informed decision on the request for
confidential treatment.

(3) Provide a second copy of the document from which you have redacted the information for which you
wish to claim confidential treatment. If you do not submit a second copy of the
document with the confidential information redacted, BSEE may assume that there is no objection to public
disclosure of the document in its entirety.

(b) In making data and information you submit available to the public,
BSEE will not disclose documents exempt from disclosure under the Freedom of Information Act (5 U.S.C. 552) and will follow the procedures set forth in the implementing regulations at 43 CFR part 2 to give submitters an opportunity to object to disclosure. (c) BSEE retains the right to make the determination with regard to any claim of confidentiality. BSEE will notify you of its decision to deny a claim, in whole or in part, and, to the extent permitted by law, will give you an opportunity to respond at least 10 days before its public disclosure.

**§ 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 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


### 64624 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

570 NONDISCRIMINATION IN THE

OUTER CONTINENTAL SHELF

580 PROSPECTING FOR MINERALS
OTHER THAN OIL, GAS, AND

SULPHUR ON THE OUTER

CONTINENTAL SHELF

581 LEASING OF MINERALS OTHER
THAN OIL, GAS, AND SULPHUR IN

THE OUTER CONTINENTAL SHELF

582 OPERATIONS IN THE OUTER

CONTINENTAL SHELF FOR MINERALS
OTHER THAN OIL, GAS, AND

SULPHUR

585 RENEWABLE ENERGY AND

ALTERNATE USES OF EXISTING

FACILITIES ON THE OUTER

CONTINENTAL SHELF

**SUBCHAPTER C—APPEALS**

590 APPEAL PROCEDURES

**SUBCHAPTER A—MINERALS REVENUE**

**MANAGEMENT**

**PART 519—DISTRIBUTION AND DISBURSEMENT OF ROYALTIES,**  **RENTALS, AND BONUSES**

**Subpart A—General Provisions [Reserved]**

**Subpart B—Oil and Gas, General [Reserved]** 

**Subpart C—[Reserved]**

**Subpart D—Oil and Gas, Offshore**

Sec. 519.410 What does this subpart contain? 519.411 What definitions apply to this subpart? 519.412 How will the qualified OCS

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

519.414 How will BOEM determine each Gulf producing State’s share of the qualified OCS revenues? 519.415 How will bonus and royalty credits

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

States?

519.417 How will BOEM calculate the percentage allocation of qualified OCS revenues to the coastal political subdivisions if, during any fiscal year, there are no applicable leased tracts in

the 181 Area in the Eastern Gulf of Mexico Planning Area?

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

Authority: Section 104, Pub. L. 97–451, 96
Stat. 2451 (30 U.S.C. 1714), Pub. L. 109–432,
Div C, Title I, 120 Stat. 3000. **Subpart A—General Provisions [Reserved]** 

**Subpart B—Oil and Gas, General [Reserved]** 

**Subpart C—[Reserved]**

**Subpart D—Oil and Gas, Offshore**

**§ 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 What definitions apply to this subpart?** 

Terms in this subpart have the following meaning:

181 Area means the area identified in map 15, page 58, of the Proposed Final
Outer Continental Shelf Oil and Gas Leasing Program for 1997–2002, dated August 1996, of the Bureau of Ocean Energy Management, available in the Office of the Director of the Bureau of Ocean Energy Management, excluding the area offered in OCS Lease Sale 181, held on December 5, 2001.

181 Area in the Eastern Planning Area is comprised of the area of overlap of the two geographic areas defined as the ‘‘181 Area’’ and the ‘‘Eastern Planning

Area.’’

181 South Area means any area— (1) Located: (i) South of the 181 Area; (ii) West of the Military Mission Line;
and

(iii) In the Central Planning Area; (2) Excluded from the Proposed Final
Outer Continental Shelf Oil and Gas Leasing Program for 1997–2002, dated August 1996, of the Bureau of Ocean Energy Management; and

(3) Included in the areas considered for oil and gas leasing, as identified in map 8, page 37, of the document entitled, Draft Proposed Program Outer Continental Shelf Oil and Gas Leasing Program 2007–2012, dated February

2006.

Applicable leased tract means a tract that is subject to a lease under section
8 of the Outer Continental Shelf Lands Act for the purpose of drilling for, developing, and producing oil or natural gas resources, and is located fully or partially in either the 181 Area in the Eastern Planning Area, or in the 181
South Area.

Central Planning Area means the Central Gulf of Mexico Planning Area of the Outer Continental Shelf, as designated in the document entitled, Draft Proposed Program Outer Continental Shelf Oil and Gas Leasing Program 2007–2012, dated February

2006.

Coastal political subdivision means a political subdivision of a Gulf producing State any part of which political subdivision is:

(1) Within the coastal zone (as defined
in section 304 of the Coastal Zone Management Act of 1972 (16 U.S.C. 1453)) of the Gulf producing State as of December 20, 2006; and

(2) Not more than 200 nautical miles from the geographic center of any leased

tract.

Coastline means the line of ordinary low water along that portion of the coast which is in direct contact with the open sea and the line marking the seaward
limit of inland waters. This is the same
definition used in section 2 of the Submerged Lands Act (43 U.S.C. 1301).

Distance means the minimum great
circle distance.

Eastern Planning Area means the Eastern Gulf of Mexico Planning Area of the Outer Continental Shelf, as designated in the document entitled,


### 64625 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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.

**§ 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. 

### R EVENUE 

### D ISTRIBUTION OF 

### Q UALIFIED 

### OCS R EVENUES 

### U NDER 

### GOMESA

Recipient of qualified OCS

revenues Percentage of qualified OCS

revenues (percent)

U.S. Treasury (General

Fund) ............................... 50

Land and Water Conservation Fund ......................... 12 .5 Gulf Producing States ........ 30Gulf Producing State Coastal Political Subdivisions .. 7 .5

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

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

**§ 519.414 How will BOEM determine each Gulf producing State’s share of the**  **qualified OCS revenues?**

(a) BOEM will determine the geographic centers of each applicable leased tract and, using the great circle distance method, will determine the closest distance from the geographic centers of each applicable leased tract to each Gulf producing State’s coastline.

(b) Based on these distances, we will calculate the qualified OCS revenues to be disbursed to each Gulf producing State using the following procedure:

(1) For each Gulf producing State, we will calculate and total, over all applicable leased tracts, the
mathematical inverses of the distances between the points on the State’s
coastline that are closest to the geographic centers of the applicable leased tracts and the geographic centers of the applicable leased tracts. For applicable leased tracts intersected by the planning area administrative boundary line, the geographic center
used for the inverse distance determination will be the geographic
center of the entire lease as if it were not
intersected.

(2) For each Gulf producing State, we
will divide the sum of each State’s inverse distances, from all applicable leased tracts, by the sum of the inverse distances from all applicable leased tracts across all four Gulf producing States. We will multiply the result by the amount of qualified OCS revenues to
be shared as shown below. In the formulas, IAL, ILA, IMS, and ITX represent the sum of the inverses of the closest distances between Alabama, Louisiana, Mississippi, and Texas and all applicable leased tracts, respectively. Alabama Share = (IAL ÷ (IAL + ILA + IMS + ITX)) × 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.

**§ 519.415 How will bonus and royalty**
**credits affect revenues allocated to Gulf producing States?** 

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

**§ 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


### 64626 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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.

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

**Area?**

If, during any fiscal year, there are no applicable leased tracts in the 181 Area in the Eastern Gulf of Mexico Planning Area, BOEM will calculate the percentage allocation of funds to the coastal political subdivisions in accordance with the following criteria:

(a) Fifty percent of the revenues will be allocated to a Gulf producing State’s coastal political subdivisions in the proportion that each coastal political subdivision’s population bears to the population of all coastal political subdivisions in the State; and

(b) Fifty percent of the revenues will be allocated to a Gulf producing State’s coastal political subdivisions in the proportion that each coastal political

subdivision’s miles of coastline bears to

the number of miles of coastline of all coastal political subdivisions in the State. Except that, for the State of Louisiana, proxy coastline lengths for coastal political subdivisions without a

coastline will be considered to be 1 ⁄ 3 the average length of the coastline of all political subdivisions within Louisiana having a coastline.

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

(a) The Office of Natural Resources Revenue (ONRR) will disburse allocated funds in the fiscal year after it collects the qualified OCS revenues. For example, ONRR will disburse funds in fiscal year 2010 from the qualified OCS revenues collected during fiscal year

2009.

(b) ONRR intends to disburse funds on or before March 31st of the year following the fiscal year of qualified

OCS revenues. **Subchapter B—OFFSHORE**

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

**Subpart A—General**

Authority and Definition of Terms

Sec. 550.101 Authority and applicability. 550.102 What does this part do?

550.103 Where can I find more information about the requirements in this part? 550.104 How may I appeal a decision made under BOEM regulations?

550.105 Definitions.

Performance Standards

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

550.117 How does a determination of well producibility affect royalty status? 550.118 [Reserved] 550.119 Will BOEM approve subsurface gas storage? 550.120–550.121 [Reserved] 550.122 What effect does subsurface storage

have on the lease term? 550.123 Will BOEM allow gas storage on

unleased lands?

Fees

550.125 Service fees. 550.126 Electronic payment instructions.

Inspection of Operations

550.130 [Reserved]

Disqualification

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

Special Types of Approvals

550.140 When will I receive an oral approval? 550.141 May I ever use alternate procedures or equipment? 550.142 How do I receive approval for departures? 550.143 How do I designate an operator? 550.144 How do I designate a new operator when a designation of operator

terminates? 550.145 How do I designate an agent or a local agent? 550.146 Who is responsible for fulfilling leasehold obligations?

Right-of-Use and Easement

550.160 When will BOEM grant me a 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? 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 (H 2 S) information must accompany the EP? 550.216 What biological, physical, and
socioeconomic information must accompany the EP? 550.217 What solid and liquid wastes and discharges information and cooling
water intake information must accompany the EP?
550.218 What air emissions information must accompany the EP?
550.219 What oil and hazardous substance spills information must accompany the

EP? 550.220 If I propose activities in the Alaska OCS Region, what planning information must accompany the EP? 550.221 What environmental monitoring information must accompany the EP? 550.222 What lease stipulations information must accompany the EP? 550.223 What mitigation measures information must accompany the EP? 550.224 What information on support vessels, offshore vehicles, and aircraft you will use must accompany the EP?

550.225 What information on the onshore support facilities you will use must accompany the EP? 550.226 What Coastal Zone Management Act (CZMA) information must accompany the EP? 550.227 What environmental impact analysis (EIA) information must accompany the EP?

550.228 What administrative information must accompany the EP?

Review and Decision Process for the EP

550.231 After receiving the EP, what will

BOEM do?

550.232 What actions will BOEM take after

the EP is deemed submitted?

550.233 What decisions will BOEM make

on the EP and within what timeframe?

550.234 How do I submit a modified EP or resubmit a disapproved EP, and when

will BOEM make a decision? 550.235 If a State objects to the EP’s coastal zone consistency certification, what can

I do?

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

550.241 What must the DPP or DOCD

include? 550.242 What information must accompany

the DPP or DOCD? 550.243 What general information must accompany the DPP or DOCD? 550.244 What geological and geophysical (G&G) information must accompany the

DPP or DOCD? 550.245 What hydrogen sulfide (H2 S) information must accompany the DPP or

DOCD?
550.246 What mineral resource

conservation information must accompany the DPP or DOCD? 550.247 What biological, physical, and

socioeconomic information must accompany the DPP or DOCD? 550.248 What solid and liquid wastes and discharges information and cooling

water intake information must accompany the DPP or DOCD? 550.249 What air emissions information must accompany the DPP or DOCD?

550.250 What oil and hazardous substance spills information must accompany the

DPP or DOCD? 550.251 If I propose activities in the Alaska OCS Region, what planning information must accompany the DPP? 550.252 What environmental monitoring information must accompany the DPP or

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

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

DOCD? 550.255 What decommissioning information must accompany the DPP or

DOCD?
550.256 What related facilities and operations information must accompany

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

DOCD?
550.258 What information on the onshore support facilities you will use must accompany the DPP or DOCD? 550.259 What sulphur operations information must accompany the DPP or

DOCD? 550.260 What Coastal Zone Management Act (CZMA) information must accompany the DPP or DOCD? 550.261 What environmental impact analysis (EIA) information must accompany the DPP or DOCD?

550.262 What administrative information must accompany the DPP or DOCD?

Review and Decision Process for the DPP or

DOCD
550.266 After receiving the DPP or DOCD,

what will BOEM do?

550.267 What actions will BOEM take after

the DPP or DOCD is deemed submitted? 550.268 How does BOEM respond to

recommendations?

550.269 How will BOEM evaluate the environmental impacts of the DPP or

DOCD?
550.270 What decisions will BOEM make

on the DPP or DOCD and within what

timeframe?

550.271 For what reasons will BOEM disapprove the DPP or DOCD? 550.272 If a State objects to the DPP’s or DOCD’s coastal zone consistency certification, what can I do?

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

or DOCD?

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

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

550.281 What must I do to conduct activities under the approved EP, DPP, or

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

Conservation Information Documents (CID)

550.296 When and how must I submit a CID

or a revision to a CID?
550.297 What information must a CID

contain? 550.298 How long will BOEM take to
evaluate and make a decision on the

CID? 550.299 What operations require approval
of the CID?

**Subpart C—Pollution Prevention and**

**Control**

550.300 [Reserved] 550.301 [Reserved] 550.302 Definitions concerning air quality.
550.303 Facilities described in a new or revised Exploration Plan or Development
and Production Plan. 550.304 Existing facilities.

**Subpart D—[Reserved]**

**Subpart E—[Reserved]**

**Subpart F—[Reserved]**

**Subpart G—[Reserved]**

**Subpart H—[Reserved]**

**Subpart I—[Reserved]**

**Subpart J—Pipelines and Pipeline Rights of Way** 
550.1011 Bond requirements for pipeline right-of-way holders.

**Subpart K—Oil and Gas Production Requirements** 

Well Tests and Surveys

550.1153 When must I conduct a static bottomhole pressure survey?

Classifying Reservoirs

550.1154 How do I determine if my

reservoir is sensitive?
550.1155 What information must I submit

for sensitive reservoirs?

Other Requirements

550.1165 What must I do for enhanced recovery operations? 550.1166 What additional reporting is required for developments in the Alaska OCS Region?

550.1167 What information must I submit with forms and for approvals?

**Subpart L—[Reserved]**

**Subpart M—[Reserved]**

**Subpart N—Outer Continental Shelf Civil**

**Penalties**

Outer Continental Shelf Lands Act Civil

Penalties

550.1400 How does BOEM begin the civil penalty process?

550.1401 Index table.

550.1402 Definitions.

550.1403 What is the maximum civil penalty?

550.1404 Which violations will BOEM review for potential civil penalties?


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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?

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 P—[Reserved]**

**Subpart Q—[Reserved]**

**Subpart R—[Reserved]**

**Subpart S—[Reserved]**

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

43 U.S.C. 1334.

**Subpart A—General**

Authority and Definition of Terms

**§ 550.101 Authority and applicability.**

The Secretary of the Interior (Secretary) authorized the Bureau of Ocean Energy Management (BOEM) to regulate oil, gas, and sulphur exploration, development, and production operations on the Outer Continental Shelf (OCS). Under the Secretary’s authority, the Director requires that all operations:

(a) Be conducted according to the OCS Lands Act (OCSLA), the regulations in this part, BOEM orders, the lease or right-of-way, and other applicable laws, regulations, and amendments; and

(b) Conform to sound conservation practice to preserve, protect, and develop mineral resources of the OCS

to:

(1) Make resources available to meet the Nation’s energy needs;

(2) Balance orderly energy resource development with protection of the human, marine, and coastal
environments;

(3) Ensure the public receives a fair and equitable return on the resources of the OCS;

(4) Preserve and maintain free enterprise competition; and

(5) Minimize or eliminate conflicts between the exploration, development, and production of oil and natural gas and the recovery of other resources.

**§ 550.102 What does this part do?**

(a) 30 CFR part 550 contains the regulations of the BOEM Offshore program that govern oil, gas, and sulphur exploration, development, and production operations on the OCS. When you conduct operations on the OCS, you must submit requests, applications, and notices, or provide supplemental information for BOEM approval.

(b) The following table of general
references shows where to look for information about these processes.



### TABLE

### —W HERE 

### TO 

### F IND 

### I NFORMATION FOR 

### C ONDUCTING 

### O PERATIONS

For information about Refer to

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

. (18) Unitization ......................................................................................... 30 CFR 250, subpart M.


### 64629 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

**§ 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.

**§ 550.105 Definitions.**

Terms used in this part will have the meanings given in the Act and as
defined in this section:

Act means the OCS Lands Act, as amended (43 U.S.C. 1331 et seq. ).

Affected State means with respect to any program, plan, lease sale, or other activity proposed, conducted, or approved under the provisions of the Act, any State:

(1) The laws of which are declared, under section 4(a)(2) of the Act, to be
the law of the United States for the portion of the OCS on which such activity is, or is proposed to be, conducted;

(2) Which is, or is proposed to be, directly connected by transportation facilities to any artificial island or installation or other device permanently or temporarily attached to the seabed;

(3) Which is receiving, or according to the proposed activity, will receive oil for processing, refining, or transshipment that was extracted from the OCS and transported directly to such State by means of vessels or by a combination of means including vessels;

(4) Which is designated by the Secretary as a State in which there is a substantial probability of significant impact on or damage to the coastal, marine, or human environment, or a State in which there will be significant changes in the social, governmental, or economic infrastructure, resulting from the exploration, development, and production of oil and gas anywhere on the OCS; or

(5) In which the Secretary finds that because of such activity there is, or will be, a significant risk of serious damage, due to factors such as prevailing winds
and currents to the marine or coastal environment in the event of any oil spill, blowout, or release of oil or gas from vessels, pipelines, or other transshipment facilities.

Air pollutant means any airborne agent or combination of agents for which the Environmental Protection Agency (EPA) has established, under section 109 of the Clean Air Act, national primary or secondary ambient air quality standards.

Analyzed geological information means data collected under a permit or a lease that have been analyzed. Analysis may include, but is not limited to, identification of lithologic and fossil content, core analysis, laboratory analyses of physical and chemical properties, well logs or charts, results from formation fluid tests, and descriptions of hydrocarbon
occurrences or hazardous conditions.

Ancillary activities mean those activities on your lease or unit that you:

(1) Conduct to obtain data and information to ensure proper exploration or development of your lease or unit; and

(2) Can conduct without BOEM approval of an application or permit.

Archaeological interest means capable of providing scientific or humanistic understanding of past human behavior, cultural adaptation, and related topics through the application of scientific or scholarly techniques, such as controlled observation, contextual measurement, controlled collection, analysis, interpretation, and explanation.

Archaeological resource means any material remains of human life or activities that are at least 50 years of age and that are of archaeological interest.

Attainment area means, for any air pollutant, an area that is shown by monitored data or that is calculated by air quality modeling (or other methods determined by the Administrator of EPA to be reliable) not to exceed any primary or secondary ambient air quality standards established by EPA.

Best available and safest technology (BAST) means the best available and safest technologies that the Director determines to be economically feasible wherever failure of equipment would have a significant effect on safety, health, or the environment.

Best available control technology (BACT) means an emission limitation based on the maximum degree of reduction for each air pollutant subject to regulation, taking into account energy, environmental and economic impacts, and other costs. The RegionalDirector 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 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


### 64630 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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 skidoff 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.

H

2 S absent means: (1) Drilling, logging, coring, testing, or producing operations have confirmed
the absence of H 2 S in concentrations that could potentially result in atmospheric concentrations of 20 ppm
or more of H2 S; or

(2) Drilling in the surrounding areas and correlation of geological and seismic data with equivalent stratigraphic units have confirmed an
absence of H2 S throughout the area to be
drilled.

H

2 S present means drilling, logging, coring, testing, or producing operations have confirmed the presence of H2 S in
concentrations and volumes that could potentially result in atmospheric concentrations of 20 ppm or more of

H 2 S.

H

2 S unknown means the designation of a zone or geologic formation where neither the presence nor absence of H2 S
has been confirmed.

Human environment means the physical, social, and economic components, conditions, and factors that interactively determine the state, condition, and quality of living conditions, employment, and health of those affected, directly or indirectly, by activities occurring on the OCS.

Interpreted geological information means geological knowledge, often in the form of schematic cross sections, 3- dimensional representations, and maps, developed by determining the geological significance of data and analyzed geological information.

Interpreted geophysical information means geophysical knowledge, often in the form of schematic cross sections, 3- dimensional representations, and maps, developed by determining the geological significance of geophysical data and analyzed geophysical information.

Lease means an agreement that is
issued under section 8 or maintained
under section 6 of the Act and that authorizes exploration for, and development and production of,
minerals. The term also means the area covered by that authorization, whichever the context requires.

Lease term pipelines mean those pipelines owned and operated by a lessee or operator that are completely
contained within the boundaries of a single lease, unit, or contiguous (not cornering) leases of that lessee or
operator.

Lessee means a person who has
entered into a lease with the United States to explore for, develop, and produce the leased minerals. The term
lessee also includes the 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.


### 64631 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

Maximum efficient rate (MER) means the maximum sustainable daily oil or gas withdrawal rate from a reservoir that will permit economic development and depletion of that reservoir without detriment to ultimate recovery.

Maximum production rate (MPR) means the approved maximum daily rate at which oil or gas may be produced from a specified oil-well or gas-well completion.

Minerals include oil, gas, sulphur, geopressured-geothermal and associated resources, and all other minerals that are authorized by an Act of Congress to be produced.

Natural resources include, without limiting the generality thereof, oil, gas, and all other minerals, and fish, shrimp, oysters, clams, crabs, lobsters, sponges, kelp, and other marine animal and plant life but does not include water power or the use of water for the production of

power.

Nonattainment area means, for any air pollutant, an area that is shown by monitored data or that is calculated by air quality modeling (or other methods determined by the Administrator of EPA to be reliable) to exceed any primary or secondary ambient air quality standard established by EPA.

Nonsensitive reservoir means a reservoir in which ultimate recovery is not decreased by high reservoir production rates.

Oil reservoir means a reservoir that contains hydrocarbons predominantly in a liquid (single-phase) state.

Oil reservoir with an associated gas

cap means a reservoir that contains hydrocarbons in both a liquid and gaseous (two-phase) state.

Oil-well completion means a well completed in an oil reservoir or in the
oil accumulation of an oil reservoir with an associated gas cap.

Operating rights mean any interest held in a lease with the right to explore for, develop, and produce leased
substances.

Operator means the person the lessee(s) designates as having control or management of operations on the leased area or a portion thereof. An operator may be a lessee, the BOEM-approved or BSEE-approved designated agent of the lessee(s), or the holder of operating rights under a BOEM-approved operating rights assignment.

Outer Continental Shelf (OCS) means all submerged lands lying seaward and
outside of the area of lands beneath navigable waters as defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301) whose subsoil and seabed appertain to the United States and are subject to its jurisdiction and control. Person includes a natural person, an association (including partnerships, joint ventures, and trusts), a State, a political subdivision of a State, or a private, public, or municipal corporation.

Pipelines are the piping, risers, and appurtenances installed for transporting oil, gas, sulphur, and produced waters.

Processed geological or geophysical information means data collected under a permit or a lease that have been processed or reprocessed. Processing involves changing the form of data to facilitate interpretation. Processing operations may include, but are not limited to, applying corrections for known perturbing causes, rearranging or filtering data, and combining or transforming data elements. Reprocessing is the additional processing other than ordinary processing used in the general course of evaluation. Reprocessing operations may include varying identified parameters for the detailed study of a specific problem area.

Production means those activities that take place after the successful completion of any means for the removal of minerals, including such removal, field operations, transfer of minerals to shore, operation monitoring, maintenance, and workover operations.

Production areas are those areas where flammable petroleum gas, volatile liquids or sulphur are produced, processed ( e.g., compressed), stored, transferred ( e.g., pumped), or otherwise handled before entering the transportation process.

Projected emissions mean emissions, either controlled or uncontrolled, from

a source or sources.

Prospect means a geologic feature having the potential for mineral deposits.

Regional Director means the BOEM officer with responsibility and authority for a Region within BOEM.

Regional Supervisor means the BOEM officer with responsibility and authority for operations or other designated program functions within a BOEM Region.

Right-of-use means any authorization issued under this part to use OCS lands.

Right-of-way pipelines are those pipelines that are contained within:

(1) The boundaries of a single lease or unit, but are not owned and operated by a lessee or operator of that lease or unit;

(2) The boundaries of contiguous (not cornering) leases that do not have a common lessee or operator;

(3) The boundaries of contiguous (not cornering) leases that have a common lessee or operator but are not owned and operated by that common lessee or
operator; or

(4) An unleased block(s).

Sensitive reservoir means a reservoir in which the production rate will affect ultimate recovery.

Significant archaeological resource means those archaeological resources that meet the criteria of significance for eligibility to the National Register of
Historic Places as defined in 36 CFR
60.4, or its successor.

Suspension means a granted or directed deferral of the requirement to produce (Suspension of Production (SOP)) or to conduct leaseholding operations (Suspension of Operations (SOO)).

Venting means the release of gas into the atmosphere without igniting it. This includes gas that is released underwater and bubbles to the atmosphere.

Waste of oil, gas, or sulphur means: (1) The physical waste of oil, gas, or sulphur;

(2) The inefficient, excessive, or improper use, or the unnecessary dissipation of reservoir energy;

(3) The locating, spacing, drilling, equipping, operating, or producing of any oil, gas, or sulphur well(s) in a
manner that causes or tends to cause a reduction in the quantity of oil, gas, or sulphur ultimately recoverable under prudent and proper operations or that causes or tends to cause unnecessary or
excessive surface loss or destruction of oil or gas; or

(4) The inefficient storage of oil. Welding means all activities connected with welding, including hot tapping and burning.

Wellbay is the area on a facility within the perimeter of the outermost
wellheads.

Well-completion operations mean the work conducted to establish production from a well after the production-casing string has been set, cemented, and pressure-tested.

Well-control fluid means drilling mud, completion fluid, or workover fluid as appropriate to the particular operation being conducted.

Western Gulf of Mexico means all OCS areas of the Gulf of Mexico except
those the BOEM Director decides are adjacent to the State of Florida. The
Western Gulf of Mexico is not the same as the Western Planning Area, an area
established for OCS lease sales.

Workover operations mean the work
conducted on wells after the initial well-completion operation for the purpose of maintaining or restoring the productivity of a well.

You means a lessee, the owner or holder of operating rights, a designated operator or agent of the lessee(s), a


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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.

Service—processing of the following: Fee amount 30 CFR citation

(1) Change in Designation of Operator ...................................... $164 ................................................ .......................................... § 550.143(d). (2) Right-of-Use and Easement for State lessee ....................... $2,569 .................................................... ................................... § 550.165. (3) [Reserved]. (4) Exploration Plan (EP) ............................................................ $3,442 for each surface location; no fee for revisions ............. § 550.211(d). (5) Development and Production Plan (DPP) or Development

Operations Coordination Document (DOCD). $3,971 for each well proposed; no fee for revisions ................ § 550.241(e).

(6) [Reserved]. (7) Conservation Information Document .................................... $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 incomplete, you are not required to submit a new fee when you submit the amended application.

(c) Verbal approvals are occasionally given in special circumstances. Any
action that will be considered a verbal permit approval requires either a paper permit application to follow the verbal approval or an electronic application submittal within 72 hours. Payment must be made with the completed paper or electronic application.

**§ 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: http://www.boem.gov/ offshore/ homepage or directly through Pay.gov at: https://www.pay.gov/ paygov/.

(a) [Reserved]

(b) You must use credit card or automated clearing house (ACH) payments through the Pay.gov Web site, and you must include a copy of the Pay.gov confirmation receipt page with your application. Inspection of Operations

**§ 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 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, You must then confirm the oral request by sending us a written request within 72 hours. (b) Request approval in writing, Give you an oral approval if quick action is needed, 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.

**§ 550.143 How do I designate an operator?**

(a) You must provide the Regional Supervisor an executed Designation of Operator form (Form BOEM–1123) unless you are the only lessee and are the only person conducting lease operations. When there is more than one lessee, each lessee must submit the Designation of Operator form and the Regional Supervisor must approve the designation before the designated operator may begin operations on the

leasehold.

(b) This designation is authority for the designated operator to act on your behalf and to fulfill your obligations under the Act, the lease, and the regulations in this part.

(c) You, or your designated operator, must immediately provide the Regional Supervisor a written notification of any change of address.

(d) If you change the designated operator on your lease, you must pay the service fee listed in § 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. **§ 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; You must pay a rental of $5 per acre per year with a minimum of $450 per year. The area subject toannual rental includes the areal extent of anchor chains, pipeline risers, and other equipment associated with the platform, artificial island, installation or device. (2) Your right-of-use and easement site

is located in water depths of 200 meters or greater; You must pay a rental of $7.50 per acre per year with a minimum of $675 per year. The area subjectto 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, BOEMmay initiate cancellation of the right-ofuse grant and easement.

**§ 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. **§ 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 thatportion 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 easementgranted under the heading of ‘‘Right-ofuse 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 siteclearance 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.

**§ 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 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. **§ 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, Items 124 through 168, 2 years after the effective date of the Sensitive Reservoir Information Report. (7) [Reserved]. (8) [Reserved].(9) BOEM–0137 OCS Plan Information, Items providing the bottomhole location, true vertical depth, and measured depth of wells, 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, All items, 2 years after the date of the survey.

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

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.


### 64637 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

If . . . 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 withsafety or environmental protection requirements, Geophysical data, Geologicaldata, Interpreted G&G information, Processed geological information, Analyzed geological information, 60 days after BOEM receives thedata or information, if the Regional Supervisor deems it necessary, BOEM will release the data and information earlier than 60 daysif the Regional Supervisor determines it is needed by affected States to make decisions under subpart B. The RegionalSupervisor will reconsider earlier release if you satisfy him/her that it would unduly damage your competitive position.(3) Your lease is no longer in effect, Geophysical data, Geologicaldata, Processed G&G information Interpreted G&G information, Analyzed geological information, When your lease terminates, This release time applies only ifthe provisions in this table governing high-resolution systems and the provisions in § 552.7 donot apply. The release time applies to the geophysical data and information only if acquiredpostlease for a lessee’s exclusive use. (4) Your lease is still in effect, Geophysical data, Processedgeophysical information, Interpreted G&G information, 10 years after you submit the data and information, This release time applies only ifthe provisions in this table governing high-resolution systems and the provisions in § 552.7 donot apply. This release time applies to the geophysical data and information only if acquiredpostlease for a lessee’s exclusive use. (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, These release times apply only ifthe provisions in this table governing high-resolution systems and the provisions in § 552.7 do not apply. If the primary termspecified in the lease is extended under the heading of ‘‘Suspensions’’ in this subpart, the extension applies to this provision.(6) Your lease is in effect and beyond the primary term specified in the lease, Geological data, Analyzed geological information, 2 years after the required submittal date, None.

(7) Data or information is submitted on well operations, Descriptions of downhole locations, operations, and equipment, When the well goes on productionor when geological data is released according to §§ 550.197(b)(5) and (b)(6), whichever occurs earlier, Directional survey data may be

released earlier to the owner of an adjacent lease according to 30 CFR 250 subpart D.

(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, Any data or information obtained, At any time, None.

(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, G&G data, analyzed geological information, processed and interpreted G&G information, Geological data and information: 10 years after BOEM issues the permit; Geophysical data: 50 years after BOEM issues thepermit; Geophysical information: 25 years after BOEM issues the permit, None.

(c) BOEM may allow limited inspection, but only by persons with a
direct interest in related BOEM decisions and issues in specific geographic areas, and who agree in writing to its confidentiality, of G&G
data and information submitted under this part or 30 CFR part 203 that BOEM

uses to:

(1) [Reserved] (2) [Reserved]

(3) [Reserved]
(4) Promote operational safety;

(5) Protect the environment; or

(6) Make field determinations.

(7) [Reserved] References

**§ 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


### 64638 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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 onOCS leases. To support the unproved and proved reserve estimation, resource assessment, and fair market value determinations. (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, ROVSurvey Report Form; and BOEM–0142, Environmental Impact Analysis Worksheet. 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, andcoastal environment, and will result in diligent exploration, development, and production of leases. (3) Subpart C, Pollution Prevention and Control (1010–0057) ................ To inform BOEM of measures to be taken to prevent air pollution. To ensure that appropriate measures are taken to prevent air pollution.(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. 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. (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. To inform BOEM of production rates for hydrocarbons produced on theOCS. To ensure economic maximization of ultimate hydrocarbon recovery.(6) Subpart N, Remedies and Penalties .................................................. The requirements in subpart N are exempt from the Paperwork Reduction Act of 1995 according to 5 CFR 1320.4.

**Subpart B—Plans and Information**

General Information

**§ 550.200 Definitions.**

Acronyms and terms used in this subpart have the following meanings:

(a) Acronyms used frequently in this subpart are listed alphabetically below:

BOEM means Bureau of Ocean Energy Management.

BSEE means Bureau of Safety and
Environmental Enforcement.

CID means Conservation Information

Document.

CZMA means Coastal Zone Management Act.

DOCD means Development Operations Coordination Document.

DPP means Development and
Production Plan.

DWOP means Deepwater Operations
Plan.

EIA means Environmental Impact Analysis.

EP means Exploration Plan.

NPDES means National Pollutant Discharge Elimination System. NTL means Notice to Lessees and Operators.

OCS means Outer Continental Shelf. (b) Terms used in this subpart are listed alphabetically below:

Amendment means a change you make to an EP, DPP, or DOCD that is pending before BOEM for a decision (see §§ 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 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 plans and documents may cover one or

more leases or units.

You must submit a(n) . . . Before you . . .

(1) Exploration Plan (EP), Conduct any exploration activities on a lease or unit. (2) Development and Production Plan (DPP), Conduct any development and production activities on a lease or unit in any OCS area other

than the Western Gulf of Mexico.(3) Development Operations Coordination Document (DOCD), Conduct any development and production activities on a lease or unit in the Western GOM.

(4) BSEE approved Deepwater Operations Plan

(DWOP), Conduct post-drilling installation activities in any water depth associated with a development project that will involve the use of a non-conventional production or completion technology. (5) Conservation Information Document (CID), Commence production from development projects in water depths greater than 1,312 feet (400 meters). (6) EP, DPP, or DOCD, Conduct geological or geophysical (G&G) exploration or a development G&G activity (see definitions under § 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.

(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.

**§ 550.202 What criteria must the Exploration Plan (EP), Development and**  **Production Plan (DPP), or Development Operations Coordination Document (DOCD)** 

**meet?**

Your EP, DPP, or DOCD must demonstrate that you have planned and are prepared to conduct the proposed
activities in a manner that:

(a) Conforms to the Outer Continental Shelf Lands Act as amended (Act), applicable implementing regulations, lease provisions and stipulations, and other Federal laws;

(b) Is safe; (c) Conforms to sound conservation practices and protects the rights of the lessor;

(d) Does not unreasonably interfere with other uses of the OCS, including those involved with National security or defense; and

(e) Does not cause undue or serious harm or damage to the human, marine,
or coastal environment.

**§ 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. **§§ 550.204 550.205 [Reserved]**

**§ 550.206 How do I submit the EP, DPP, or**

**DOCD?**

(a) Number of copies. When you submit an EP, DPP, or DOCD to BOEM, you must provide:

(1) Four copies that contain all required information (proprietary copies);

(2) Eight copies for public distribution (public information copies) that omit information that you assert is exempt
from disclosure under the Freedom of Information Act (FOIA) (5 U.S.C. 552) and the implementing regulations (43 CFR part 2); and

(3) Any additional copies that may be necessary to facilitate review of the EP, DPP, or DOCD by certain affected States and other reviewing entities.

(b) Electronic submission. You may submit part or all of your EP, DPP, or DOCD and its accompanying information electronically. If you prefer to submit your EP, DPP, or DOCD electronically, ask the Regional Supervisor for further guidance.

(c) Withdrawal after submission. You may withdraw your proposed EP, DPP, or DOCD at any time for any reason. Notify the appropriate BOEM OCS Region if you do.

Ancillary Activities

**§ 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 (H 2 S) 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.

**§ 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. **§ 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; (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.

**§ 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 thetop 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 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 (H** 2**S) information must accompany the EP?** 

The following H 2 S information, as applicable, must accompany your EP:

(a) Concentration. The estimated concentration of any H 2 S 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 H 2 S absent, H 2 S present, or H 2 S unknown. Provide sufficient information to justify your request.

(c) H 2 S Contingency Plan . If you ask the Regional Supervisor to classify the area of your proposed exploration
activities as either H 2 S present or H 2 S unknown, an H 2 S Contingency Plan prepared under 30 CFR 250.490(f), or a reference to an approved or submitted

H 2 S Contingency Plan that covers the proposed exploration activities.

(d) Modeling report. If you modeled a potential H 2 S 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 H2 S release from your proposed exploration

activities.

(2) If any H 2 S 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 sulphur dioxide (SO 2), particulate
matter in the form of PM 10 and PM2.5 when applicable, nitrogen oxides (NO X), 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 SO 2 , PM, NO X , 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 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.

**§ 550.223 What mitigation measures information must accompany the EP?** 

(a) If you propose to use any measures beyond those required by the regulations in this part to minimize or mitigate environmental impacts from your proposed exploration activities, a description of the measures you will use must accompany your EP.

(b) If there is reason to believe that protected species may be incidentally taken by planned exploration activities, you must include mitigation measures designed to avoid or minimize the
incidental take of:

(1) Threatened and endangered species listed under the ESA; and (2) Marine mammals, as appropriate, if you have not already received authorization for incidental take as may be necessary under the MMPA.

**§ 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. (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; (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 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 calendardays 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 Regional Supervisor will take one of the following actions:

The regional supervisor will . . . If . . . And then . . .

(1) Approve your EP, It complies with all applicable requirements, The Regional Supervisor will notify you in writing of thedecision and may require you to meet certain conditions, including those to provide monitoring information. (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, 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. (3) Disapprove your EP, Your proposed activities would probably cause seriousharm or damage to life (including fish or other aquatic life); property; any mineral (in areas leased or notleased); the National security or defense; or the marine, coastal, or human environment; and you cannotmodify your proposed activities to avoid such condition(s), (i) The Regional Supervisor will notify you in writing ofthe 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.

**§ 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. (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 What must the DPP or DOCD**

**include?**

Your DPP or DOCD must include the following:

(a) Description, objectives, and
schedule. A description, discussion of the objectives, and tentative schedule (from start to completion) of the development and production activities you propose to undertake. Examples of development and production activities
include:

(1) Development drilling; (2) Well test flaring; (3) Installation of production platforms, satellite structures, subsea wellheads and manifolds, and lease term pipelines (see definition at § 550.105); and

(4) Installation of production facilities and conduct of production operations.

(b) Location. The location and water depth of each of your proposed wells and production facilities. Include a map showing the surface and bottom-hole location and water depth of each proposed well, the surface location of each production facility, and the locations of all associated drilling unit and construction barge anchors.

(c) Drilling unit. A description of the drilling unit and associated equipment you will use to conduct your proposed development drilling activities. Include a brief description of its important safety and pollution prevention features, and a table indicating the type and the estimated maximum quantity of fuels and oil that will be stored on the facility (see definition of ‘‘facility (3)’’ under § 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.

**§ 550.243 What general information must accompany the DPP or DOCD?** 

The following general information must accompany your DPP or DOCD:

(a) Applications and permits. A listing, including filing or approval status, of the Federal, State, and local application approvals or permits you must obtain to carry out your proposed development and production activities.

(b) Drilling fluids. A table showing the projected amount, discharge rate, and chemical constituents for each type (i.e., water based, oil based, synthetic based) of drilling fluid you plan to use to drill your proposed development wells.

(c) Production. The following production information:

(1) Estimates of the average and peak rates of production for each type of production and the life of the reservoir(s) you intend to produce; and

(2) The chemical and physical characteristics of the produced oil (see definition under 30 CFR 254.6) that you will handle or store at the facilities you will use to conduct your proposed development and production activities.

(d) Chemical products. A table showing the name and brief description, quantities to be stored, storage method, and rates of usage of the chemical products you will use to conduct your proposed development and production activities. You need list only those chemical products you will store or use in quantities greater than the amounts defined as Reportable Quantities in 40 CFR part 302, or amounts specified by the Regional Supervisor.

(e) New or unusual technology. A description and discussion of any new or unusual technology (see definition under § 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. **§ 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.

**§ 550.245 What hydrogen sulfide (H** 2**S) information must accompany the DPP or** 

**DOCD?**

The following H 2 S information, as applicable, must accompany your DPP

or DOCD:

(a) Concentration. The estimated concentration of any H 2 S 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 H 2 S absent, H 2 S present, or H2 S unknown. Provide sufficient information to justify your
request.

(c) H 2 S Contingency Plan . If you request that the Regional Supervisor classify the area of your proposed development and production activities
as either H 2 S present or H 2 S unknown,

an H2 S Contingency Plan prepared under 30 CFR 250.490(f), or a reference to an approved or submitted H 2 S 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 H 2 S 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 H2 S 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

H 2 S release from your proposed

activities.

(3) If any H 2 S 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. **§ 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: (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 (SO 2), particulate
matter in the form of PM 10 and PM2.5 when applicable, nitrogen oxides (NO X),


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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. (e) Non-exempt facilities. A description of how you will comply with § 550.303 when the projected
emissions of SO 2 , PM, NO X , 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 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.

**§ 550.256 What related facilities and operations information must accompany** 
**the DPP or DOCD?**

The following information regarding facilities and operations directly related to your proposed development and production activities must accompany your DPP or DOCD.

(a) OCS facilities and operations. A description and location of any of the following that directly relate to your proposed development and production

activities:

(1) Drilling units; (2) Production platforms; (3) Right-of-way pipelines (including those that transport chemical products and produced water); and

(4) Other facilities and operations located on the OCS (regardless of ownership).

(b) Transportation system. A discussion of the transportation system that you will use to transport your production to shore, including:

(1) Routes of any new pipelines; (2) Information concerning barges and shuttle tankers, including the storage capacity of the transport vessel(s), and
the number of transfers that will take place per year;

(3) Information concerning any intermediate storage or processing facilities; (4) An estimate of the quantities of oil, gas, or sulphur to be transported from your production facilities; and

(5) A description and location of the primary onshore terminal.

**§ 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. **§ 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 timetablefor 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).

**§ 550.261 What environmental impact analysis (EIA) information must accompany** 

**the DPP or DOCD?**

The following EIA information must accompany your DPP or DOCD:

(a) General requirements. Your EIA

must:

(1) Assess the potential environmental impacts of your proposed development and production activities;

(2) Be project specific; and (3) Be as detailed as necessary to assist the Regional Supervisor in complying with the NEPA of 1969 (42

U.S.C. 4321 et seq. ) and other relevant
Federal laws such as the ESA and the

MMPA.

(b) Resources, conditions, and

activities. Your EIA must describe those resources, conditions, and activities listed below that could be affected by your proposed development and production activities, or that could affect the construction and operation of
facilities or structures or the activities proposed in your DPP or DOCD.

(1) Meteorology, oceanography, geology, and shallow geological or manmade hazards;

(2) Air and water quality; (3) Benthic communities, marine mammals, sea turtles, coastal and marine birds, fish and shellfish, and plant life;

(4) Threatened or endangered species and their critical habitat;

(5) Sensitive biological resources or habitats such as essential fish habitat, refuges, preserves, special management areas identified in coastal management programs, sanctuaries, rookeries, and calving grounds;

(6) Archaeological resources; (7) Socioeconomic resources (including the approximate number, timing, and duration of employment of persons engaged in onshore support and construction activities), population (including the approximate number of people and families added to local onshore areas), existing offshore and onshore infrastructure (including major sources of supplies, services, energy, and water), types of contractors or vendors that may place a demand on local goods and services, land use,
subsistence resources and harvest practices, recreation, recreational and commercial fishing (including seasons, location, and type), minority and lower income groups, and CZMA programs;

(8) Coastal and marine uses such as military activities, shipping, and mineral exploration or development;
and

(9) Other resources, conditions, and activities identified by the Regional Supervisor.

(c) Environmental impacts. Your EIA

must:

(1) Analyze the potential direct and indirect impacts (including those from accidents, cooling water intake structures, and those identified in relevant ESA biological opinions such as, but not limited to, those from noise, vessel collisions, and marine trash and debris) that your proposed development and production activities will have on the identified resources, conditions, and
activities;

(2) Describe the type, severity, and duration of these potential impacts and their biological, physical, and other consequences and implications;

(3) Describe potential measures to minimize or mitigate these potential impacts;

(4) Describe any alternatives to your proposed development and production activities that you considered while developing your DPP or DOCD, and compare the potential environmental impacts; and

(5) Summarize the information you incorporate by reference.

(d) Consultation. Your EIA must include a list of agencies and persons with whom you consulted, or with whom you will be consulting, regarding potential impacts associated with your proposed development and production

activities.

(e) References cited. Your EIA must include a list of the references that you
cite in the EIA.

**§ 550.262 What administrative information must accompany the DPP or DOCD?** 

The following administrative information must accompany your DPP

or DOCD:

(a) Exempted information description (public information copies only). A description of the general subject matter of the proprietary information that is included in the proprietary copies of your DPP or DOCD or its accompanying
information.

(b) Bibliography. (1) If you reference a previously submitted EP, DPP, DOCD, study report, survey report, or other material in your DPP or DOCD or its accompanying information, a list of the referenced material; and

(2) The location(s) where the Regional Supervisor can inspect the cited referenced material if you have not
submitted it.

Review and Decision Process for the

DPP or DOCD

**§ 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 calendardays 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 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 RegionalSupervisor 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:

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 andmay require you to meet certain conditions, including those to provide monitoring information.


### 64652 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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, 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, Any of the reasons in § 550.271 apply, (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.

**§ 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). (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 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.

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

(a) Approvals and permits. Before you conduct activities under your approved EP, DPP, or DOCD you must obtain the following approvals and or permits, as applicable, from the District Manager or BSEE Regional Supervisor:

(1) Approval of applications for permits to drill (APDs) (see 30 CFR 250.410);

(2) Approval of production safety systems (see 30 CFR 250.800);

(3) Approval of new platforms and other structures (or major modifications to platforms and other structures) (see 30 CFR 250.905);

(4) Approval of applications to install lease term pipelines (see 30 CFR 250.1007); and

(5) Other permits, as required by applicable law.

(b) Conformance. The activities proposed in these applications and permits must conform to the activities described in detail in your approved EP,
DPP, or DOCD.

(c) Separate State CZMA consistency

review. APDs, and other applications for licenses, approvals, or permits to conduct activities under your approved EP, DPP, or DOCD including those identified in paragraph (a) of this section, are not subject to separate State CZMA consistency review.

(d) Approval restrictions for permits for activities conducted under EPs. The Regional Supervisor will not approve any APDs or other applications for licenses, approvals, or permits under your approved EP until either:

(1) All affected States with approved coastal zone management programs concur, or are conclusively presumed to concur, with the coastal zone consistency certification accompanying your EP under section 307(c)(3)(B)(i) and (ii) of the CZMA (16 U.S.C. 1456(c)(3)(B)(i) and (ii)); or

(2) The Secretary of Commerce finds, under section 307(c)(3)(B)(iii) of the CZMA (16 U.S.C.1456(c)(3)(B)(iii)) that each activity covered by the EP is consistent with the objectives of the CZMA or is otherwise necessary in the interest of National security;

(3) If an affected State objects to the coastal zone consistency certification accompanying your approved EP after BOEM has approved your EP, you may
either:

(i) Revise your EP to accommodate the State’s objection and submit the revision to the Regional Supervisor for approval;

or (ii) Appeal the State’s objection to the Secretary of Commerce using the procedures in 15 CFR part 930, subpart H. The Secretary of Commerce will
either:

(A) Grant your appeal by making the finding described in paragraph (d)(2) of this section; or

(B) Deny your appeal, in which case you may revise your EP as described in paragraph (d)(3)(i) of this section.

**§ 550.282 Do I have to conduct post approval monitoring?** 

After approving your EP, DPP, or DOCD, the Regional Supervisor may direct you to conduct monitoring programs, including monitoring in
accordance with the ESA and the MMPA. You must retain copies of all monitoring data obtained or derived from your monitoring programs and make them available to the BOEM upon request. The Regional Supervisor may require you to:

(a) Monitoring plans. Submit monitoring plans for approval before you begin the work; and

(b) Monitoring reports. Prepare and submit reports that summarize and analyze data and information obtained or derived from your monitoring programs. The Regional Supervisor will specify requirements for preparing and submitting these reports.

**§ 550.283 When must I revise or supplement the approved EP, DPP, or** 
**DOCD?**

(a) Revised OCS plans. You must revise your approved EP, DPP, or DOCD when you propose to: (1) Change the type of drilling rig ( e.g., jack-up, platform rig, barge, submersible, semisubmersible, or drillship), production facility ( e.g., caisson, fixed platform with piles, tension leg platform), or transportation mode ( e.g., pipeline, barge);

(2) Change the surface location of a well or production platform by a distance more than that specified by the Regional Supervisor;

(3) Change the type of production or significantly increase the volume of production or storage capacity;

(4) Increase the emissions of an air pollutant to an amount that exceeds the amount specified in your approved EP,
DPP, or DOCD;

(5) Significantly increase the amount of solid or liquid wastes to be handled or discharged;

(6) Request a new H2 S area classification, or increase the
concentration of H 2 S 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.

**§ 550.297 What information must a CID**

**contain?**

(a) You must base the CID on wells drilled before your CID submittal that
define the extent of the reservoirs. You must notify BOEM of any well that is drilled to total depth during the CID evaluation period and you may be required to update your CID.

(b) You must include all of the following information if available. Information must be provided for each hydrocarbon-bearing reservoir that is penetrated by a well that would meet the producibility requirements of § 550.115 or § 550.116: (1) General discussion of the overall development of the reservoir;

(2) Summary spreadsheets of well log data and reservoir parameters (i.e., sand tops and bases, fluid contacts, net pay, porosity, water saturations, pressures, formation volume factor);

(3) Appropriate well logs, including digital well log (i.e., gamma ray, resistivity, neutron, density, sonic, caliper curves) curves in an acceptable digital format;

(4) Sidewall core/whole core and pressure-volume-temperature analysis;

(5) Structure maps, with the existing and proposed penetration points and subsea depths for all wells penetrating the reservoirs, fluid contacts (or the lowest or highest known levels in the absence of actual contacts), reservoir boundaries, and the scale of the map;

(6) Interpreted structural cross sections and corresponding interpreted seismic lines or block diagrams, as necessary, that include all current wellbores and planned wellbores on the leases or units to be developed, the reservoir boundaries, fluid contacts, depth scale, stratigraphic positions, and relative biostratigraphic ages;

(7) Isopach maps of each reservoir showing the net feet of pay for each well
within the reservoir identified at the penetration point, along with the well name, labeled contours, and scale;

(8) Estimates of original oil and gas 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 (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 150- calendar-day evaluation period if there is missing, inconclusive, or inaccurate data, or when a well reaches total depth during the evaluation period. BOEM may also suspend the evaluation periodwhen 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 [Reserved]**

**§ 550.302 Definitions concerning air quality.** 

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


### 64655 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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 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 (SO 2), nitrogen oxides (NO X), 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:



### S IGNIFICANCE 

### L EVELS

### —A IR 

### P OLLUTANT 

### C ONCENTRATIONS

[μg/m 3]

Air pollutant Averaging time (hours)

Annual 24 8 3 1

SO 2

....................................................................................... 1 5

........................ 25

......... ............... TSP ...................................................................................... 1 5

........................ .......... .............. ........................ NO 2

...................................................................................... 1 ........................ ...............

......... ........................ ........................ CO ........................................................................................ ........................ ............. ........... 500 ........................ 2,000

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


### 64656 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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 SO 2 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:



### M AXIMUM 

### A LLOWABLE 

### C ONCENTRATION 

### I NCREASES

[μg/m 3]

Air pollutant Averaging times

Annual mean 1 24-hour
maximum 3-hour
maximum

Class I:

TSP ............................................................................................................................ ........... 5 10 ........................
SO 2

............................................................................................................................... ........ 2 5 25
Class II:

TSP ............................................................................................................................ ........... 19 37 ........................
SO 2

............................................................................................................................... ........ 20 91 512
Class III:

TSP ............................................................................................................................ ........... 37 75 ........................
SO 2

............................................................................................................................... ........ 40 182 700

1 For TSP—geometric; For SO 2—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 SO 2 so that concentrations in the onshore
ambient air of an attainment or
unclassifiable area do not exceed the
maximum allowable increases.

(3)(i) The projected emissions of VOC from any facility, except a temporary facility, which significantly affect the onshore air quality of a nonattainment area shall be fully reduced. This shall be done through the application of BACT and, if additional reductions are necessary, through the application of additional emission controls or through the acquisition of offshore or onshore
offsets.

(ii) The projected emissions of VOC from any facility which significantly affect the onshore air quality of an attainment area shall be reduced through the application of BACT.

(4)(i) If projected emissions from a facility significantly affect the onshore air quality of both a nonattainment and an attainment or unclassifiable area, the regulatory requirements applicable to projected emissions significantly affecting a nonattainment area shall apply.

(ii) If projected emissions from a facility significantly affect the onshore air quality of more than one class of attainment area, the lessee must reduce projected emissions to meet the maximum allowable increases specified for each class in paragraph (g)(2)(i) of
this section.

(h) Controls required on temporary facilities. The lessee shall apply BACT to reduce projected emissions of any air pollutant from a temporary facility which significantly affects the air quality of an onshore area of a State.

(i) Emission offsets. When emission offsets are to be obtained, the lessee
must demonstrate that the offsets are equivalent in nature and quantity to the projected emissions that must be reduced after the application of BACT; a binding commitment exists between
the lessee and the owner or owners of the source or sources; the appropriate air quality control jurisdiction has been
notified of the need to revise the State Implementation Plan to include the information regarding the offsets; and the required offsets come from sources which affect the air quality of the area significantly affected by the lessee’s offshore operations.

(j) Review of facilities with emissions below the exemption amount. If, during the review of a new, modified, or revised Exploration Plan or Development and Production Plan, the Regional Supervisor determines or an
affected State submits information to the Regional Supervisor which demonstrates, in the judgment of the Regional Supervisor, that projected emissions from an otherwise exempt facility will, either individually or in
combination with other facilities in the area, significantly affect the air quality of an onshore area, then the Regional Supervisor shall require the lessee to
submit additional information to
determine whether emission control measures are necessary. The lessee shall be given the opportunity to present information to the Regional Supervisor which demonstrates that the exempt facility is not significantly affecting the air quality of an onshore area of the

State.

(k) Emission monitoring requirements. The lessee shall monitor, in a manner approved or prescribed by the Regional Supervisor, emissions from the facility.
The lessee shall submit this information monthly in a manner and form


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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 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 = 3400D 2/3 for CO; and E = 33.3D for TSP, SO 2 , NO X , 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:



### S IGNIFICANCE 

### L EVELS

### —A IR 

### P OLLUTANT 

### C ONCENTRATIONS

[μG/M 3]

Air pollutant Averaging time (hours)

Annual 24 8 3 1

SO 2

....................................................................................... 1 5

........................ 25

......... ............... TSP ...................................................................................... 1 5

........................ .......... .............. ........................ NO 2

...................................................................................... 1 ........................ ...............

......... ........................ ........................ CO ........................................................................................ ........................ ............. ........... 500 ........................ 2,000

(d) Significance determinations. (1) The projected emissions of any air pollutant other than VOC from any facility which result in an onshore
ambient air concentration above the significance levels determined under paragraph (c) of this section for that air pollutant shall be deemed to significantly affect the air quality of the onshore area for that air pollutant.

(2) The projected emissions of VOC from any facility which is not exempt under paragraph (b) of this section for that air pollutant shall be deemed to significantly affect the air quality of the
onshore area for VOC.

(e) Controls required. (1) The projected emissions of any air pollutant which significantly affect the air quality
of an onshore area shall be reduced through the application of BACT.

(2) The lessee shall submit a compliance schedule for the application of BACT. If it is necessary to cease operations to allow for the installation of emission controls, the lessee may apply for a suspension of operations under the provisions of 30 CFR 250.174.

(f) Review of facilities with emissions below the exemption amount. If, during the review of the information required under paragraph (a)(6) of this section, the Regional Supervisor determines or
an affected State submits information to the Regional Supervisor which demonstrates, in the judgment of the Regional Supervisor, that projected emissions from an otherwise exempt facility will, either individually or in
combination with other facilities in the area, significantly affect the air quality of an onshore area, then the Regional Supervisor shall require the lessee to
submit additional information to
determine whether control measures are necessary. The lessee shall be given the opportunity to present information to the Regional Supervisor which demonstrates that the exempt facility is not significantly affecting the air quality
of an onshore area of the State.

(g) Emission monitoring requirements. The lessee shall monitor, in a manner approved or prescribed by the Regional


### 64658 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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. (2) A reservoir with three or more producing

completions, 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.

(b) Your bottomhole pressure survey must meet the following requirements:

(1) You must shut-in the well for a minimum period of 4 hours to ensure stabilized conditions; and

(2) The bottomhole pressure survey must consist of a pressure measurement at mid-perforation, and pressure measurements and gradient information for at least four gradient stops coming
out of the hole.

(c) You must submit to the Regional Supervisor the results of all static bottomhole pressure surveys on Form BOEM–140, Bottomhole Pressure Survey Report, within 60 days after the date of the survey.

(d) The Regional Supervisor may grant a departure from the requirement to run a static bottomhole pressure survey. To request a departure, you must submit a justification, along with Form BOEM–140, Bottomhole Pressure Survey Report, showing a calculated bottomhole pressure or any measured
data. Classifying Reservoirs

**§ 550.1154 How do I determine if my**

**reservoir is sensitive?**

(a) You must determine whether each reservoir is sensitive. You must classify
the reservoir as sensitive if:

(1) Under initial conditions it is an oil reservoir with an associated gas cap;

(2) At any time there are near-critical fluids; or

(3) The reservoir is undergoing enhanced recovery.

(b) For the purposes of this subpart,
near-critical fluids are:

(1) Those fluids that occur in high temperature, high-pressure reservoirs where it is not possible to define the liquid-gas contact; or

(2) Fluids in reservoirs that are near bubble point or dew point conditions.

(c) The Regional Supervisor may reclassify a reservoir when available
information warrants reclassification.

(d) If available information indicates that a reservoir previously classified as non-sensitive is now sensitive, you must submit a request to the Regional Supervisor to reclassify the reservoir. You must include supporting information, as listed in the table in § 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?**

(a) [Reserved] (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:

SRI BOEM–0127 (2 copies) Reservoir reclassification

(a) Maps: (1) Base map with surface, bottomhole, and completion locations with respect to the

unit or lease line and the orientation of representative seismic lines or cross-sections ............................................................................................................................... ........................................ ........................................ (2) Structure maps with penetration point and subsea 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 ............................................................................................................................ ........................................ √

√ Required. * Additional items the Regional Supervisor may request.Note: All maps must be at a standard scale and show lease and unit lines. The Regional Supervisor may waive submittal of some of the required data on a case-by-case basis.

(f) Depending on the type of approval requested, you must submit the appropriate payment of the service fee(s) listed in § 550.125, according to the instructions in § 550.126.


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**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?** 

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

**§ 550.1401 Index table.**

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

(a) Definitions ................................................................................................................ .................................................................... § 550.1402 (b) What is the maximum civil penalty? ......................................................................................... .................................................. § 550.1403 (c) Which violations will BOEM review for potential civil penalties? ........................................................... ..................................... § 550.1404 (d) When is a case file developed? ............................................................................................. ..................................................... § 550.1405 (e) When will BOEM notify me and provide penalty information? .................................................................. ................................. § 550.1406 (f) How do I respond to the letter of notification? ............................................................................ ................................................ § 550.1407 (g) When will I be notified of the Reviewing Officer’s decision? ............................................................... ....................................... § 550.1408 (h) What are my appeal rights? ................................................................................................. ....................................................... § 550.1409

**§ 550.1402 Definitions.**

Terms used in this subpart have the following meaning:

Case file means a BOEM document file containing information and the record of evidence related to the alleged
violation.

Civil penalty means a fine. It is a BOEM regulatory enforcement tool used
in addition to Notices of Incidents of Noncompliance and directed suspensions of production or other operations.

Reviewing Officer means a BOEM employee assigned to review case files and assess civil penalties.

Violation means failure to comply
with the Outer Continental Shelf Lands Act (OCSLA) or any other applicable laws, with any regulations issued under the OCSLA, or with the terms or provisions of leases, licenses, permits, rights-of-way, or other approvals issued
under the OCSLA.

Violator means a person responsible
for a violation.

**§ 550.1403 What is the maximum civil penalty?** 

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

**§ 550.1404 Which violations will BOEM review for potential civil penalties?** 

BOEM will review each of the following violations for potential civil penalties:

(a) Violations that you do not correct within the period BOEM grants;

(b) [Reserved] (c) [Reserved] (d) Violations of the oil spill financial responsibility requirements at 30 CFR
part 553. **§ 550.1405 When is a case file developed?** BOEM will develop a case file during its investigation of the violation, and forward it to a Reviewing Officer if any of the conditions in § 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.

**§ 550.1406 When will BOEM notify me and provide penalty information?** 

If the Reviewing Officer determines that a civil penalty should be assessed, the Reviewing Officer will send the
violator a letter of notification. The
letter of notification will include:

(a) The amount of the proposed civil penalty;

(b) Information on the violation(s);
and

(c) Instruction on how to obtain a copy of the case file, schedule a meeting, submit information, or pay the penalty.

**§ 550.1407 How do I respond to the letter**

**of notification?**

You have 30 calendar days after you receive the Reviewing Officer’s letter to
either:

(a) Request, in writing, a meeting with the Reviewing Officer;

(b) Submit additional information; or (c) Pay the proposed civil penalty.

**§ 550.1408 When will I be notified of the Reviewing Officer’s decision?** 

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

**§ 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 penaltywas 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 What definitions apply to this subpart?** 

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

Penalties After a Period to Correct

**§ 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?**

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 What if I do not correct the**

**violation?**

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

(b) If you do not correct all of the
violations identified in the Notice of Noncompliance within 40 days after you receive the Notice of Noncompliance (or 20 days following the expiration of a longer time period specified in that Notice), we may increase the penalty to up to $5,000 per day, beginning with the date of the Notice of Noncompliance, for each violation for as long as you do not
correct the violations.

**§ 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). **§ 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.

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. **§ 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, 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 How may BOEM collect the penalty?** 

(a) BOEM may use all available means to collect the penalty including, but not
limited to:

(1) Requiring the lease surety, for amounts owed by lessees, to pay the penalty;

(2) Deducting the amount of the penalty from any sums the United States owes to you; and

(3) Using judicial process to compel your payment under 30 U.S.C. 1719(k).

(b) If the Department uses judicial process, or if you seek judicial review under § 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

**§ 550.1490 What standards must my BOEM-specified surety instrument meet?** 

(a) A BOEM-specified surety instrument must be in a form specified in BOEM instructions. BOEM will give you written information and standard forms for BOEM-specified surety instrument requirements.

(b) BOEM will use a bank-rating
service to determine whether a financial institution has an acceptable rating to provide a surety instrument adequate to indemnify the lessor from loss or damage.

(1) Administrative appeal bonds must be issued by a qualified surety company which the Department of the Treasury has approved.

(2) Irrevocable letters of credit or certificates of deposit must be from a financial institution acceptable to BOEM with a minimum 1-year period of coverage subject to automatic renewal
up to 5 years.

**§ 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. Financial Solvency Requirements

**§ 550.1495 How do I demonstrate financial solvency?** 

(a) To demonstrate financial solvency under this part, you must submit an audited consolidated balance sheet, and,if requested by the BOEM 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.

**§ 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 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.

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 a lease that have been analyzed. Analysis may include, but is not limited to, identification of lithologic and fossil content, core analyses, laboratory analyses of physical and chemical properties, well logs or charts, results from formation fluid tests, and descriptions of hydrocarbon
occurrences or hazardous conditions.

Archaeological interest means capable of providing scientific or humanistic understanding of past human behavior, cultural adaptation, and related topics through the application of scientific or scholarly techniques, such as controlled observation, contextual measurements, controlled collection, analysis, interpretation, and explanation.

Archaeological resources mean any material remains of human life or activities that are at least 50 years of age and of archaeological interest.

Coastal environment means the physical, atmospheric, and biological components, conditions, and factors that interactively determine the productivity, state, condition, and quality of the terrestrial ecosystem from
the shoreline inward to the boundaries
of the coastal zone.

Coastal Zone means the coastal waters (including the lands therein and thereunder) and the adjacent shorelands (including the waters therein and thereunder), strongly influenced by each other and in proximity to the shorelines
of the several coastal States and extends
seaward to the outer limit of the U.S.
territorial sea.

Coastal Zone Management Act means the Coastal Zone Management Act of 1972, as amended (16 U.S.C. 1451 et

seq. ).

Data means facts, statistics, measurements, or samples that have not been analyzed, processed, or interpreted.

Deep stratigraphic test means drilling that involves the penetration into the sea bottom of more than 500 feet (152 meters).

Director means the Director of the Bureau of Ocean Energy Management, U.S. Department of the Interior, or a
subordinate authorized to act on the
Director’s behalf.

Exploration means the commercial search for oil, gas, and sulphur. Activities classified as exploration include, but are not limited to:

(1) Geological and geophysical marine and airborne surveys where magnetic, gravity, seismic reflection, seismic refraction, gas sniffers, coring, or other systems are used to detect or imply the presence of oil, gas, or sulphur; and

(2) Any drilling, whether on or off a geological structure. Geological and geophysical scientific
research means any oil, gas, or sulphur related investigation conducted in the
OCS for scientific and/or research purposes. Geological, geophysical, and geochemical data and information gathered and analyzed are made available to the public for inspection and reproduction at the earliest practicable time. The term does not include commercial geological or geophysical exploration or research.

Geological exploration means exploration that uses geological and geochemical techniques ( e.g., coring and test drilling, well logging, and bottom sampling) to produce data and information on oil, gas, and sulphur resources in support of possible exploration and development activities. The term does not include geological
scientific research.

Geological information means geological or geochemical data that have been analyzed, processed, or interpreted.

Geophysical data means measurements that have not been processed or interpreted.

Geophysical exploration means exploration that utilizes geophysical techniques ( e.g., gravity, magnetic, electromagnetic, or seismic) to produce data and information on oil, gas, and sulphur resources in support of possible exploration and development activities. The term does not include geophysical
scientific research.

Geophysical information means geophysical data that have been processed or interpreted.

Governor means the Governor of a State or the person or entity lawfully designated to exercise the powers granted to a Governor pursuant to the

Act.

Human environment means the physical, social, and economic components, conditions, and factors which interactively determine the state, condition, and quality of living conditions, employment, and health of those affected, directly or indirectly, by activities occurring on the OCS.

Hydrocarbon occurrence means the direct or indirect detection during drilling operations of any liquid or gaseous hydrocarbons by examination of well cuttings, cores, gas detector readings, formation fluid tests, wireline logs, or by any other means. The term does not include background gas, minor accumulations of gas, or heavy oil residues on cuttings and cores.

Interpreted geological information means knowledge, often in the form of schematic cross sections, 3-dimensional representations, and maps, developed by determining the geological


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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: (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 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 Authority and applicability of this part.** 

BOEM authorizes you to conduct exploration or scientific research activities under this part in accordance with the Act, the regulations in this part, orders of the Director/Regional Director, and other applicable statutes, regulations, and amendments.

(a) This part does not apply to G&G exploration conducted by or on behalf
of the lessee on a lease in the OCS. Refer to 30 CFR part 250 if you plan to conduct G&G activities related to oil, gas, or sulphur under terms of a lease.

(b) Federal agencies are exempt from the regulations in this part.

(c) G&G exploration or G&G scientific
research related to minerals other than oil, gas, and sulphur is covered by regulations at 30 CFR part 580.

**§ 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 30- day Notice, you must provide oral notification and followup in writing. You must also inform BOEM in writing when you conclude your work.

**§ 551.5 Applying for permits or filing**

**Notices.**

(a) Permits. You must submit a signed original and three copies of the BOEM permit application form (Form BOEM– 0327). The form includes names of persons; the type, location, purpose, and dates of activity; and environmental and
other information. A nonrefundable service fee of $2,012 must be paid electronically through Pay.gov at: https://www.pay.gov/paygov/, and you must include a copy of the Pay.gov confirmation receipt page with your application.

(b) Disapproval of permit application. If BOEM disapproves your application for a permit, the Regional Director will
state the reasons for the denial and will advise you of the changes needed to obtain approval.

(c) Notices. You must sign and date a
Notice and state:

(1) The name(s) of the person(s) who will conduct the proposed research;

(2) The name(s) of any other person(s) participating in the proposed research, including the sponsor;

(3) The type of research and a brief description of how you will conduct it;

(4) The location in the OCS, indicated on a map, plat, or chart, where you will conduct research;

(5) The proposed dates you project for your research activity to start and end;

(6) The name, registry number, registered owner, and port of registry of vessels used in the operation;

(7) The earliest practicable time you expect to make the data and information resulting from your research activity available to the public; (8) Your plan of how you will make the data and information you collected available to the public;

(9) That you and others involved will
not sell or withhold for exclusive use the data and information resulting from your research; and

(10) At your option, you may submit (as a substitute for the material required in paragraphs (c)(7), (c)(8), and (c)(9) of this section) the nonexclusive use agreement for scientific research
attachment to Form BOEM–0327.

(d) Filing locations. You must apply for a permit or file a Notice at one of the following locations:

(1) For the OCS off the State of Alaska—the Regional Supervisor for Resource Evaluation, Bureau of Ocean Energy Management, Alaska OCS Region, 3801 Centerpoint Drive, Suite # 500, Anchorage, Alaska 99503–58232.

(2) For the OCS off the Atlantic Coast and in the Gulf of Mexico—the Regional Supervisor for Resource Evaluation, Bureau of Ocean Energy Management, Gulf of Mexico OCS Region, 1201 Elmwood Park Boulevard, New Orleans,

Louisiana 70123–2394.

(3) For the OCS off the coast of the States of California, Oregon, Washington, or Hawaii—the Regional Supervisor for Resource Evaluation, Bureau of Ocean Energy Management, Pacific OCS Region, 770 Paseo Camarillo, Camarillo, California 93010–

6064.

**§ 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 endangeroperations 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 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. (v) A description of any unavoidable
or irreversible adverse effects on the
environment that could occur.

(vi) Other relevant data that the BOEM Regional Director requires.

(3) Copies for coastal States. You must submit copies of the drilling plan and environmental report to the BOEM Regional Director for transmittal to the
Governor of each affected coastal State and the coastal zone management agency of each affected coastal State that has an approved program under the Coastal Zone Management Act. (BOEM Regional Director will make the drilling plan and environmental report available to appropriate Federal agencies and the public according to the Department of the Interior’s policies and procedures).

(4) Certification of coastal zone management program consistency and

State concurrence. When required under an approved coastal zone management program of an affected State, your drilling plan must include a certification that the proposed activities described in the plan comply with enforceable policies of, and will be
conducted in a manner consistent with such State’s program. BOEM Regional Director may not approve any of the activities described in the drilling plan
unless the State concurs with the consistency certification or the Secretary of Commerce makes the finding authorized by section 307(c)(3)(B)(iii) of the Coastal Zone Management Act.

(5) Protecting archaeological

resources. If the Regional Director believes that an archaeological resource may exist in the area that may be affected by drilling, the Regional Director will notify you of the need to prepare an archaeological report.

(i) If the evidence suggests that an archaeological resource may be present,
you must:

(A) Locate the site of the drilling so as to not adversely affect the area where the archaeological resources may be, or

(B) Establish to the satisfaction of the BOEM Regional Director that an archaeological resource does not exist or will not be adversely affected by drilling. This must be done by further archaeological investigation, conducted by an archaeologist and a geophysicist, using survey equipment and techniques deemed necessary by the Regional Director. A report on the investigation
must be submitted to the BOEM Regional Director for review.

(ii) If the BOEM Regional Director determines that an archaeological resource is likely to be present in the area that may be affected by drilling, and may be adversely affected by drilling, the BOEM Regional Director will notify you immediately. You must take no action that may adversely affect the archaeological resource unless an investigation by BOEM determines that the resource is not archaeologically significant.

(iii) If you discover any archaeological resource while drilling, you must immediately halt drilling and report the discovery to the BOEM Regional Director. If investigations determine that the resource is significant, the BOEM Regional Director will inform you how to protect it.

(6) [Reserved] (7) Revising an approved drilling plan. Before you revise an approved drilling plan, you must obtain the BOEM Regional Director’s approval.

(8) [Reserved] (9) Deadline for completing a deep stratigraphic test. If your deep stratigraphic test well is within 50 geographic miles of a tract that BOEM has identified for a future lease sale, as listed on the currently approved OCS leasing schedule, you must complete all drilling activities and submit the data and information to the BOEM Regional Director at least 60 days before the first day of the month in which BOEM schedules the lease sale. However, the BOEM Regional Director may extend your permit duration to allow you to complete drilling activities and submit
data and information if the extension is
in the National interest.

(c) Group participation in test drilling. BOEM encourages group participation for deep stratigraphic tests.

(1) Purpose of group participation. The purpose is to minimize duplicative G&G activities involving drilling into
the seabed of the OCS.

(2) Providing opportunity for participation in a deep stratigraphic

test. When you propose to drill a deep stratigraphic test, you must give all interested persons an opportunity to participate in the test drilling through a signed agreement on a cost-sharing basis. You may include a penalty for late participation of not more than 100 percent of the cost to each original participant in addition to the original
share cost.

(i) The participants must assess and distribute late participation penalties in
accordance with the terms of the
agreement.

(ii) For a significant hydrocarbon occurrence that the Regional Director announces to the public, the penalty for subsequent late participants may be raised to not more than 300 percent of the cost of each original participant in addition to the original share cost.

(3) Providing opportunity for participation in a shallow test drilling


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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 toparticipate 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. (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. **§ 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.

**§ 551.11 Submission, inspection, and selection of geological data and information**  **collected under a permit and processed by permittees or third parties.** 

(a) Availability of geological data and information collected under a permit. (1) You must notify the Regional Director, in writing, when you complete the initial analysis, processing, or interpretation of any geological data and information. Initial analysis and processing are the stages of analysis or processing where the data and
information first become available for in-house interpretation by the permittee, or become available commercially to third parties via sale, trade, license agreement, or other means.

(2) The Regional Director may ask if you have further analyzed, processed, or interpreted any geological data and information. When so asked, you must respond to BOEM in writing within 30 days.

(b) Submission, inspection, and selection of geological data and information. The Regional Director may request the permittee or third party to submit the analyzed, processed, and interpreted geologic data and information for inspection and/or permanent retention by BOEM. The data
and information must be submitted within 30 days after such request.

(c) Requirements for submission of geological data and information collected under a permit. Unless the Regional Director specifies otherwise, geological data and information must
include:

(1) An accurate and complete record of all geological (including geochemical) data and information describing each operation of analysis, processing, and interpretation;

(2) Paleontological reports identifying microscopic fossils by depth, including
the reference datum to which paleontological sample depths are related and, if the Regional Director requests, washed samples that you maintain for paleontological determinations;

(3) Copies of well logs or charts in a digital format, if available;

(4) Results and data obtained from formation fluid tests; (5) Analyses of core or bottom samples and/or a representative cut or split of the core or bottom sample;

(6) Detailed descriptions of any hydrocarbons or hazardous conditions encountered during operations, including near losses of well control, abnormal geopressures, and losses of circulation; and

(7) Other geological data and information that the Regional Director may specify.

(d) Obligations when geological data and information collected under permit are obtained by a third party. A third party may obtain geological data and information from a permittee, or from another third party, by sale, trade, license agreement, or other means. If this happens:

(1) The third party recipient of the
data and information assumes the obligations under this section, except for the notification provisions of paragraph (a)(1), and is subject to the penalty provisions of 30 CFR part 550, subpart N; and

(2) A permittee or third party that sells, trades, licenses, or otherwise provides data and information to a third party must advise the recipient, in writing, that accepting these obligations is a condition precedent of the sale, trade, license, or other agreement; and

(3) Except for license agreements, a permittee or third party that sells, trades, or otherwise provides data and information to a third party must advise the Regional Director, in writing and within 30 days, of the sale, trade, or other agreement, including the identity of the recipient of the data and information; or

(4) For license agreements a permittee or third party that licenses data and information to a third party must, within 30 days of a request by the Regional Director, advise the Regional Director, in writing, of the license agreement, including the identity of the recipient of the data and information.

**§ 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. (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:

If you or a third party submit and BOEM retains . . . The Regional Director will release them to the public . . .

(i) Geological data and information, 10 years after BOEM issued the permit. (ii) Geophysical data, 50 years after BOEM issued the permit. (iii) Geophysical information processed or reprocessed less than 20

years after BOEM issued the germane permit, 25 years after BOEM issued the permit.

(iv) Geophysical information processed or reprocessed 20 or more

years after BOEM issued the germane permit, 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 BOEMapproved the application for an extension. In any case BOEM will release the information no later than 50 years after BOEM issued the permit.

(2) Permittees and third parties may apply to BOEM for an extension of the 25-year proprietary term for geophysical information reprocessed 20 or more years after BOEM issued the germane permit. You must submit the application to BOEM within 90 days after completion of the reprocessing, except during the initial 1-year grace period as provided in paragraph (b)(5) below. Filing locations are listed in § 551.5(d). Your application must
include:

(i) Name and address of the permittee or third party;

(ii) Product name;
(iii) Identification of the geophysical information area;

(iv) Identification of originating permit number and date;

(v) Description of reprocessing performed; (vi) Identification of the date of completion of reprocessing the geophysical information;

(vii) Certification that the product meets the definition of processed geophysical information and that all other information in the application is accurate; and

(viii) Signature and date. (3) With each new reprocessing of permitted data, you may apply for an extension of up to 5 years. However, the


### 64671 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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 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 (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.

**§ 552.2 Definitions.**

When used in the regulations in this part, the following terms shall have the meanings given below:

Act refers to the Outer Continental Shelf Lands Act, as amended (43 U.S.C.

1331 et seq. ).

Affected local government means the principal governing body of a locality
which is in an affected State and is identified by the Governor of that State as a locality which will be significantly affected by oil and gas activities on the

OCS.

Affected State means, with respect to any program, plan, lease sale, or other activity, proposed, conducted, or approved pursuant to the provisions of the Act, any State:

(1) The laws of which are declared, pursuant to section 4(a)(2)(A) of the Act,
to be the law of the United States for the portion of the OCS on which such activity is, or is proposed to be, conducted;

(2) Which is, or is proposed to be, directly connected by transportation facilities to any artificial island or
installations and other devices permanently, or temporarily attached to the seabed;

(3) Which is receiving, or in accordance with the proposed activity will receive, oil for processing, refining, or transshipment which was extracted from the OCS and transported directly to such State by means of vessels or by a combination of means including vessels; (4) Which is designated by the
Director as a State in which there is a substantial probability of significant impact on or damage to the coastal, marine, or human environment, or a State in which there will be significant changes in the social, governmental, or economic infrastructure, resulting from the exploration, development, and production of oil and gas anywhere on the OCS; or

(5) In which the Director finds that because of such activity there is, or will be, a significant risk of serious damage, due to factors such as prevailing winds and currents, to the marine or coastal environment in the event of any oilspill, blowout, or release of oil or gas from vessels, pipelines, or other transshipment facilities.

Analyzed geological information means data collected under a permit or a lease which have been analyzed. Analysis may include, but is not limited to, identification of lithologic and fossil content, core analyses, laboratory analyses of physical and chemical properties, logs or charts of electrical, radioactive, sonic, and other well logs, and descriptions of hydrocarbon shows
or hazardous conditions.

Area adjacent to a State means all of that portion of the OCS included within a planning area if such planning area is bordered by that State. The portion of the OCS in the Navarin Basin Planning Area is deemed to be adjacent to the
State of Alaska. The States of New York
and Rhode Island are deemed to be adjacent to both the Mid-Atlantic Planning Area and the North Atlantic Planning Area.

Data means facts and statistics or samples which have not been analyzed or processed.

Development means those activities which take place following discovery of oil or natural gas in paying quantities, including geophysical activity, drilling, platform construction, and operation of all onshore support facilities, and which are for the purpose of ultimately producing the oil and gas discovered.

Director means the Director of the Bureau of Ocean Energy Management of the U.S. Department of the Interior or a designee of the Director.

Exploration means the process of searching for oil and natural gas, including:

(1) Geophysical surveys where magnetic, gravity, seismic, or other systems are used to detect or imply the presence of such oil or natural gas, and

(2) Any drilling, whether on or off known geological structures, including the drilling of a well in which a discovery of oil or natural gas in paying quantities is made and the drilling of any additional delineation well after such discovery which is needed to delineate any reservoir and to enable the lessee to determine whether to proceed with development and production.

Governor means the Governor of a State, or the person or entity designated by, or pursuant to, State law to exercise the powers granted to a Governor pursuant to the Act.

Information, when used without a qualifying adjective, includes analyzed geological information, processed geophysical information, interpreted geological information, and interpreted geophysical information.

Interpreted geological information means knowledge, often in the form of schematic cross sections and maps, developed by determining the geological significance of data and analyzed geological information.

Interpreted geophysical information means knowledge, often in the form of schematic cross sections and maps, developed by determining the geological significance of geophysical data and processed geophysical information.

Lease means any form of
authorization which is issued under
section 8 or maintained under section 6
of the Act and which authorizes exploration for, and development and production of, oil or natural gas, or the land covered by such authorization, whichever is required by the context.

Lessee means the party authorized by a lease, or an approved assignment thereof, to explore for and develop and produce the leased deposits in accordance with the regulations in part 550 of this chapter, including all parties holding such authority by or through
the lessee.

Outer Continental Shelf (OCS) means all submerged lands which lie seaward
and outside of the area of lands beneath navigable waters as defined in the Submerged Lands Act (67 Stat. 29) and
of which the subsoil and seabed appertain to the United States and are subject to its jurisdiction and control.

Permittee means the party authorized by a permit issued pursuant to part 551 of this chapter to conduct activities on
the OCS.

Processed geophysical information means data collected under a permit or a lease which have been processed. Processing involves changing the form of data so as to facilitate interpretation. Processing operations may include, but are not limited to, applying corrections for known perturbing causes, rearranging or filtering data, and combining or transforming data
elements.

Production means those activities which take place after the successful


### 64673 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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.

**§ 552.3 Oil and gas data and information to be provided for use in the OCS Oil and Gas**  **Information Program.**

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

(b)(1) Whenever a lessee or permittee provides any data or information, at the request of the Director and specifically
for use in the OCS Oil and Gas Information Program in a form and manner of processing which is utilized by the lessee or permittee in the normal conduct of business, the Director shall pay the reasonable cost of reproducing
the data and information if the lessee or permittee requests reimbursement. The cost shall be computed and paid in accordance with the applicable provisions of paragraph (e)(1) of this

section.

(2) Whenever a lessee or permittee provides any data or information, at the request of the Director and specifically
for use in the OCS Oil and Gas Information Program, in a form and manner of processing not normally utilized by the lessee or permittee in the normal conduct of business, the Director shall pay the lessee or permittee, if the lessee or permittee requests reimbursement, the reasonable cost of processing and reproducing the requested data and information. The cost is to be computed and paid in accordance with the applicable provisions of paragraph (e)(2) of this

section.

(c) Data or information requested by the Director shall be provided as soon as practicable, but not later than 30 days following receipt of the Director’s request, unless, for good reason, the Director authorizes a longer time period for the submission of the requested data
or information.

(d) The Director reserves the right to disclose any data or information acquired from a lessee or permittee to an independent contractor or agent for the purpose of reproducing, processing, reprocessing, or interpreting such data or information. When practicable, the Director shall notify the lessee(s) or permittee(s) who provided the data or
information of the intent to disclose the data or information to an independent contractor or agent. The Director’s
notice of intent will afford the permittee(s) or lessee(s) a period of not less than 5 working days within which
to comment on the intended action.
When the Director so notifies a lessee or permittee of the intent to disclose data or information to an independent contractor or agent, all other owners of
such data or information shall be
deemed to have been notified of the Director’s intent. Prior to any such disclosure, the contractor or agent shall be required to execute a written commitment not to disclose any data or information to anyone without the express consent of the Director, and not to make any disclosure or use of the
data or information other than that provided in the contract. Contracts between BOEM and independent
contractors shall be available to the lessee(s) or permittee(s) for inspection. In the event of any unauthorized use or disclosure of data or information by the contractor or agent, or by an employee thereof, the responsible contractor or agent or employee thereof shall be liable for penalties pursuant to section 24 of
the Act.

(e)(1) After delivery of data or
information in accordance with paragraph (b)(1) of this section and upon receipt of a request for reimbursement and a determination by the Director that the requested reimbursement is proper, the lessee or permittee shall be reimbursed for the cost of reproducing the data or information at the lessee’s or permittee’s
lowest rate or at the lowest commercial rate established in the area, whichever is less. Requests for reimbursement must be made within 60 days of the delivery date of the data or information requested under paragraph (b)(1) of this

section.

(2) After delivery of data or
information in accordance with paragraph (b)(3) of this section, and upon receipt of a request for reimbursement and a determination by the Director that the requested reimbursement is proper, the lessee or permittee shall be reimbursed for the cost of processing or reprocessing and of reproducing the requested data or information. Requests for
reimbursement must be made within 60 days of the delivery date of the data or information and shall be for only the costs attributable to processing or reprocessing and reproducing, as distinguished from the costs of data acquisition.

(3) Requests for reimbursement are to
contain a breakdown of costs in sufficient detail to allow separation of reproduction, processing, and reprocessing costs from acquisition and
other costs.

(f) Each Federal Department or Agency shall provide the Director with any data which it has obtained pursuant to section 11 of the Act and any other information which may be necessary or useful to assist the Director in carrying out the provisions of the Act.

**§ 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


### 64674 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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.

**§ 552.6 Freedom of Information Act requirements.** 

(a) The Director shall make data and
information available in accordance with the requirements and subject to the
limitations of the Freedom of Information Act (5 U.S.C. 552), the regulations contained in 43 CFR part 2 (Records and Testimony), the requirements of the Act, and the regulations contained in 30 CFR parts 250 and 550 (Oil and Gas and Sulphur Operations in the Outer Continental Shelf) and 30 CFR part 551 (Geological and Geophysical Explorations of the Outer Continental Shelf).

(b) Except as provided in § 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 (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.

**PART 553—OIL SPILL FINANCIAL**
**RESPONSIBILITY FOR OFFSHORE**
**FACILITIES**

**Subpart A—General**

Sec. 553.1 What is the purpose of this part?
553.3 How are the terms used in this regulation defined? 553.5 What is the authority for collecting Oil Spill Financial Responsibility (OSFR) information?

**Subpart B—Applicability and Amount of**

**OSFR**

553.10 What facilities does this part cover?

553.11 Who must demonstrate OSFR? 553.12 May I ask BOEM for a determination

of whether I must demonstrate OSFR?

553.13 How much OSFR must I

demonstrate?

553.14 How do I determine the worst case oil-spill discharge volume? 553.15 What are my general OSFR compliance responsibilities?

**Subpart C—Methods for Demonstrating**

**OSFR**

553.20 What methods may I use to

demonstrate OSFR?

553.21 How can I use self-insurance as

OSFR evidence? 553.22 How do I apply to use self-insurance

as OSFR evidence?

553.23 What information must I submit to support my net worth demonstration?

553.24 When I submit audited annual financial statements to verify my net worth, what standards must they meet? 553.25 What financial test procedures must

I use to determine the amount of 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? 553.43 When is my OSFR demonstration or the amendment to my OSFR

demonstration effective? 553.44 [Reserved] 553.45 Where do I send my OSFR evidence?

**Subpart E—Revocation and Penalties**

553.50 How can BOEM refuse or invalidate my OSFR evidence? 553.51 What are the penalties for not complying with this part?

**Subpart F—Claims for Oil-Spill Removal Costs and Damages** 

553.60 To whom may I present a claim? 553.61 When is a guarantor subject to direct

action for claims? 553.62 What are the designated applicant’s notification obligations regarding a

claim?

Appendix to Part 553—List of U.S. Geological Survey Topographic Maps

Authority: 33 U.S.C. 2716, 28 U.S.C. 2461.

**Subpart A—General**

**§ 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 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 GeographicNames 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 1:63,360- scale USGS topographic map on which
it is shown.

Guarantor means a person other than a responsible party who provides OSFR evidence for a designated applicant.

Guaranty means any acceptable form of OSFR evidence provided by a guarantor including an indemnity, insurance, or surety bond.

Incident means any occurrence or series of occurrences having the same origin that results in the discharge or substantial threat of the discharge of oil.

Indemnity means an agreement to indemnify a designated applicant upon
its satisfaction of a claim.


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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 (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 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 What facilities does this part**

**cover?**

(a) This part applies to any COF on any lease or permit issued or on any RUE granted under the OCSLA or applicable State law.

(b) For a pipeline COF that extends onto land, this part applies to that portion of the pipeline lying seaward of
the first accessible flow shut-off device
on land.

**§ 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.


### 64677 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

(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, The amount of OSFR that applies to the COF. More than one COF, The highest amount of OSFR that applies to any one of the COFs.

(b) You must demonstrate OSFR in the amounts specified in this section: (1) For a COF located wholly or partially in the OCS you must demonstrate OSFR in accordance with the following table:

COF worst case oil-spill discharge volume Applicable amount of

OSFR

Over 1,000 bbls but not more than 35,000 bbls .................................................................................. ............................................... $35,000,000 Over 35,000 but not more than 70,000 bbls ...................................................................................... ................................................. 70,000,000 Over 70,000 but not more than 105,000 bbls ..................................................................................... ................................................ 105,000,000 Over 105,000 bbls .............................................................................................................. ................................................................. 150,000,000

(2) For a COF not located in the OCS you must demonstrate OSFR in accordance with the following table:

COF worst case oil-spill discharge volume Applicable amount of

OSFR

Over 1,000 bbls but not more than 10,000 bbls .................................................................................. ............................................... $10,000,000 Over 10,000 but not more than 35,000 bbls ...................................................................................... ................................................. 35,000,000 Over 35,000 but not more than 70,000 bbls ...................................................................................... ................................................. 70,000,000 Over 70,000 but not more than 105,000 bbls ..................................................................................... ................................................ 105,000,000 Over 105,000 bbls .............................................................................................................. ................................................................. 150,000,000

(3) The Director may determine that you must demonstrate an amount of OSFR greater than the amount in paragraphs (b)(1) and (2) of this section based on the relative operational, environmental, human health, and other risks that your COF poses. The Director may require an amount that is one or more levels higher than the amount indicated in paragraph (b)(1) or (2) of this section for your COF. The Director will not require an OSFR demonstration that exceeds $150 million.

(4) You must demonstrate OSFR in the lowest amount specified in the applicable table in paragraph (b)(1) or (2) of this section for a facility with a potential worst case oil-spill discharge of 1,000 bbls or less if the Director notifies you in writing that the demonstration is justified by the risks of the potential oil-spill discharge.

**§ 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 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** 

**§ 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 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 self**
**insurance as OSFR evidence?**

(a) You must submit a complete Form BOEM–1018 with each application to demonstrate OSFR using self-insurance.

(b) You must submit your application to renew OSFR using self-insurance by the first calendar day of the 5th month after the close of your fiscal year. You may submit to BOEM your initial application to demonstrate OSFR using self-insurance at any time.

**§ 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 (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 self**

**insurance allowed as OSFR evidence based**

**on net worth?**

(a) Divide the total amount of the stockholders’/owners’ equity listed on the balance sheet by ten.

(b) Divide the net amount of the identifiable U.S. assets by the net
amount of the identifiable total assets.

(c) Multiply the net amount of plant, property, and equipment shown on the balance sheet by the number calculated under paragraph (b) of this section and divide the resultant product by ten.

(d) The smaller of the numbers calculated under paragraphs (a) or (c) of
this section is the maximum allowable amount you may use to demonstrate
OSFR under this method.

**§ 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


### 64679 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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 self**

**insurance allowed as OSFR evidence based**

**on unencumbered assets?**

(a) Divide the total amount of the stockholders’/owners’ equity listed on the balance sheet by 4.

(b) Divide the value of the unencumbered U.S. assets by 2.

(c) The smaller number calculated under paragraphs (a) or (b) of this
section is the maximum allowable amount you may use to demonstrate
OSFR under this method.

**§ 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 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.

**§ 553.30 How can I use an indemnity as**
**OSFR evidence?**

(a) You may use only one indemnity issued by only one indemnitor to satisfy all or part of your obligation to
demonstrate OSFR.

(b) Your indemnitor must be your corporate parent or affiliate.

(c) Your indemnitor must complete a Form BOEM–1018 and provide an indemnity that: (1) Includes all the information required by § 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** 

**§ 553.40 What OSFR evidence must I**

**submit to BOEM?**

(a) You must submit to BOEM: (1) A single demonstration of OSFR that covers all the COFs for which you are the designated applicant;

(2) A completed and unaltered Form
BOEM–1016;

(3) BOEM forms that identify your COFs (Form BOEM–1021, Form BOEM– 1022), and the methods you will use to


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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.

**§ 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 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 How can I amend my list of**

**COFs?**

(a) If you want to add a COF that is not identified in your current OSFR demonstration, you must submit to BOEM a completed Form BOEM–1022. If applicable, you also must submit any additional indemnities, surety bonds, insurance certificates, or other instruments required to extend the coverage of your original OSFR

demonstration to the COFs to be added. You do not need to resubmit previously accepted audited annual financial statements for the current fiscal year.

(b) If you want to drop a COF identified in your current OSFR demonstration, you must submit to BOEM a completed Form BOEM–1022.

You must continue to demonstrate OSFR for the COF until BOEM approves

OSFR evidence for the COF from another designated applicant, or OSFR is no longer required ( e.g., until a well that is a COF is properly plugged and abandoned).

**§ 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. **§ 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 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. (2) An assertion of insolvency or petition in bankruptcy under 11 U.S.C.

chapter 7 or 11, (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.

(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.

**§ 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. **§ 553.62 What are the designated applicant’s notification obligations**  **regarding a claim?**

If you are a designated applicant, and you receive a claim for removal costs and damages, then within 15 calendar days of receipt of a claim you must notify:

(a) Your guarantors; and (b) The responsible parties for whom you are acting as the designated applicant.

Appendix to Part 553—List of U.S. Geological Survey Topographic Maps

Alabama (1:24,000 scale): Bellefontaine; Bon Secour Bay; Bridgehead; Coden; Daphne; Fort Morgan; Fort Morgan NW; Grand Bay; Grand Bay SW; Gulf Shores; Heron Bay; Hollingers Island; Isle Aux Herbes; Kreole; Lillian; Little Dauphin Island; Little Point Clear; Magnolia Springs; Mobile; Orange Beach; Perdido Beach; Petit Bois Island; Petit Bois Pass; Pine Beach; Point Clear; Saint Andrews Bay; West Pensacola.

Alaska (1:63,360 scale): Afognak (A–1, A–
2, A–3, A–4, A–5, A–0&B–0, B–1, B–2, B–3, C–1&2, C–2&3, C–5, C–6, D–1, D–4, D–5); Anchorage (A–1, A–2, A–3, A–4, A–8, B–7, B–8); Barrow (A–1, A–2, A–3, A–4, A–5, B– 3, B–4); Baird Mts. (A–6); Barter Island (A– 3, A–4, A–5); Beechy Point (A–1, A–2, B–1, B–2, B–3, B–4, B–5, C–4, C–5); Bering Glacier (A–1, A–2, A–3, A–4, A–5, A–6, A–7, A–8); Black (A–1, A–2, B–1, C–1); Blying Sound (C–7, C–8, D–1&2, D–3, D–4, D–5, D–6, D–7, D–8); Candle (D–6); Cordova (A–1, A–2, A–
3, A–4, A–7&8, B–2, B–3, B–4, B–5, B–6, B– 7, B–8, C–5, C–6, C–7, C–8, D–6, D–7, D–8); De Long Mts. (D–4, D–5); Demarcation Point (C–1, C–2, D–2, D–3); Flaxman Island (A–1, A–3, A–4, A–5, B–5); Harrison Bay (B–1, B– 2, B–3, B–4, C–1, C–3, C–4, C–5, D–4, D–5); Icy Bay (D1, D–2&3); Iliamna (A–2, A–3, A– 4, B–2, B–3, C–1, C–2, D–1); Karluk (A–1, A– 2, B–2, B–3, C–1, C–2, C–4&5, C–6); Kenai (A–4, A–5, A–7, A–8, B–4, B–6, B–7, B–8, C– 4, C–5, C–6, C–7, D–1, D–2, D–3, D–4, D–5); Kodiak (A–3, A–4, A–5, A–6, B–1&2, B–3, B–
4, B–6, C–1, C–2, C–3, C–5, C–6, D–1, D–2, D–3, D–4, D–5, D–6); Kotzebue (A–1, A–2, A–
3, A–4, B–4, B–6, C–1, C–4, C–5, C–6, D–1, D–2); Kwiguk (C–6, D–6); Meade River (D–1, D–3, D–4, D–5); Middleton Island (B–7, D– 1&2); Mt. Katmai (A–1, A–2, A–3; B–1); Mt. Michelson (D–1, D–2, D–3); Mt. St. Elias (A– 5); Noatak (A–1, A–2, A–3, A–4, B–4, C–4, C– 5, D–6, D–7); Nome (B–1, C–1, C–2, C–3, D– 3, D–4, D–7); Norton Bay (A–4, B–4, B–5, B– 6, C–4, C–5, C–6, D–4, D–5, D–6); Point Hope (A–1, A–2, B–2, B–3, C–2, C–3, D–1, D–2); Point Lay (A–3&4, B–2&3, C–2, D–1, D–2); Selawik (A–5, A–6, B–5, B–6, C–5, C–6, D– 6); Seldovia (A–3, A–4, A–5, A–6, B–1, B–2,
B–3, B–4, B–5, B–6, C–1, C–2, C–3, C–4, C– 5, D–1, D–3, D–4, D–5, D–8); Seward (A–1,
A–2, A–3, A–4, A–5, A–6, A–7, B–1, B–2, B– 3, B–4, B–5, C–1, C–2, C–3, C–4, C–5, D–1, D–2, D–3, D–4, D–5, D–6, D–7, D–8); Shishmaref (A–2, A–3, A–4, B–1, B–2, B–3); Solomon (B–2, B–3, B–6, C–1, C–2, C–3, C– 4, C–5, C–6); St. Michael (A–2, A–3, A–4, A– 5, A–6, B–1, B–2, C–1, C–2); Teller (A–2, A–
3, A–4, B–3, B–4, B–5, B–6, C–6, C–7, D–4, D–5, D–6, D–8); Teshekpuk (D–1, D–2, D–3, D–4, D–5); Tyonek (A–1, A–2, A–3, A–4, B– 1, B–2); Unalakleet (B–5, B–6, C–4, C–5, D– 4); Valdez (A–7, A–8); Wainwright (A–5, A–
6&7, B–2, B–3, B–4, B–5&6, C–2, C–3, D–1, D–2; Yakutat (A–1, A–2, A–2, B–3, B–4, B–
5, C–4, C–5, C–6, C–7, C–8, D–3, D–4, D–5, D–6, D–8).

California (1:24,000 scale): Arroyo Grande NE; Beverly Hills; Carpinteria; Casmalia; Dana Point; Del Mar; Dos Pueblos Canyon; Encinitas; Gaviota; Goleta; Guadalupe; Imperial Beach; Laguna Beach; La Jolla; Las Pulgas Canyon; Lompoc Hills; Long Beach; Los Alamitos; Malibu Beach; Morro Bay


### 64682 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

South; National City; Newport Beach; Oceano; Oceanside; Oxnard; Pismo Beach; Pitas Point; Point Arguello; Point Conception; Point Dune; Point Loma; Point Mugu; Point Sal; Port San Luis; Rancho Santa Fe; Redondo Beach; Sacate; San Clemente; San Juan Capistrano; San Luis Rey; San Onofre Bluff; San Pedro; Santa Barbara; Saticoy; Seal Beach; Surf; Tajiguas; Topanga; Torrance; Tranquillon Mountain; Triunfo Pass; Tustin; Venice; Ventura; White Ledge

Peak.

Florida (1:24,000 scale): Allanton; Alligator Bay; Anna Maria; Apalachicola; Aripeka; Bayport; Beacon Beach; Beacon Hill; Bee Ridge; Belle Meade; Belle Meade NW; Beverly; Big Lostmans Bay; Bird Keys; Bokeelia; Bonita Springs; Bradenton; Bradenton Beach; Bruce; Bunker; Cape Romano; Cape Saint George; Cape San Blas; Captiva; Carrabelle; Cedar Key; Chassahowitzka; Chassahowitzka Bay; Chiefland SW; Choctaw Beach; Chokoloskee; Clearwater; Clive Key; Cobb Rocks; Cockroach Bay; Crawfordville East; Crooked Island; Crooked Point; Cross City SW; Crystal River; Destin; Dog Island; Dunedin; East Pass; Egmont Key; El Jobean; Elfers; Englewood; Englewood NW; Estero; Everglades City; Fivay Junction; Flamingo; Fort Barrancas; Fort Myers Beach; Fort Myers SW; Fort Walton Beach; Freeport; Gandy Bridge; Garcon Point; Gator Hook Swamp; Gibsonton; Goose Island; Grayton Beach; Green Point; Gulf Breeze; Harney River; Harold SE; Holley; Holt SW; Homosassa; Horseshoe Beach; Indian Pass; Jackson River; Jena; Keaton Beach; Laguna Beach; Lake Ingraham East; Lake Ingraham West; Lake Wimico; Laurel; Lebanon Station; Lighthouse Point; Lillian; Long Point; Lostmans River Ranger Station; Manlin Hammock; Marco Island; Mary Esther; Matlacha; McIntyre; Milton South; Miramar Beach; Myakka River; Naples North; Naples South; Navarre; New Inlet; Niceville; Nutall Rise; Ochopee; Okefenokee Slough; Oldsmar; Orange Beach; Oriole Beach; Overstreet; Ozello; Pace; Palmetto; Panama City; Panama City Beach; Panther Key; Pass-A-Grille Beach; Pavillion Key; Pensacola; Perdido Bay; Pickett Bay; Pine Island Center; Placida; Plover Key; Point Washington; Port Boca Grande; Port Richey; Port Richey NE; Port Saint Joe; Port Tampa; Punta Gorda; Punta Gorda SE; Punta Gorda SW; Red Head; Red Level; Rock Islands; Royal Palm Hammock; Safety Harbor; Saint Joseph Point; Saint Joseph Spit; Saint Marks; Saint Marks NE; Saint Petersburg; Saint Teresa Beach; Salem SW; Sandy Key; Sanibel; Sarasota; Seahorse Key; Seminole; Seminole Hills; Shark Point; Shark River Island; Shired Island; Snipe Island; Sopchoppy; South of Holley; Southport; Sprague Island; Spring Creek; Springfield; Steinhatchee; Steinhatchee SE; Steinhatchee SW; Sugar Hill; Sumner; Suwannee; Tampa; Tarpon Springs; Valparaiso; Venice; Vista; Waccassasa Bay; Ward Basin; Warrior Swamp; Weavers Station; Weeki Wachee Spring; West Bay; West Pass; West Pensacola; Whitewater Bay West; Withlacoochee Bay; Wulfert; Yankeetown.

Louisiana (1:24,000 scale): Alligator Point; Barataria Pass; Bastian Bay; Bay Batiste; Bay Coquette; Bay Courant; Bay Dosgris; Bay Ronquille; Bay Tambour; Bayou Blanc; Bayou Lucien; Belle Isle; Belle Pass; Big Constance Lake; Black Bay North; Black Bay South; Breton Islands; Breton Islands SE; Buras; Burrwood Bayou East; Burwood Bayou West; Calumet Island; Cameron; Caminada Pass; Cat Island; Cat Island Pass; Central Isles Dernieres; Chandeleur Light; Chef Mentur; Cheniere Au Tigre; Cocodrie; Coquille Point; Cow Island; Creole; Cypremort Point; Deep Lake; Dixon Bay; Dog Lake; Door Point; East Bay Junop; Eastern Isles; Dernieres; Ellerslie; Empire; English Lookout; False Mouth Bayou; Fearman Lake; Floating Turf Bayou; Fourleague Bay; Franklin; Freemason Island; Garden Island Pass; Grand Bayou; Grand Bayou du Large; Grand Chenier; Grand Gosier Islands; Grand Isle; Hackberry Beach; Hammock Lake; Happy Jack; Hebert Lake; Hell Hole Bayou; Hog Bayou; Holly Beach; Intercoastal City; Isle Au Pitre; Jacko Bay; Johnson Bayou; Kemper; Lake Athanasio; Lake Cuatro Caballo; Lake Eloi; Lake Eugene; Lake Felicity; Lake La Graisse; Lake Merchant; Lake Point; Lake Salve; Lake Tambour; Leeville; Lena Lagoon; Lost Lake; Main Pass; Malheureux Point; Marone Point; Martello Castle; Mink Bayou; Mitchell Key; Morgan City SW; Morgan Harbor; Mound Point; Mulberry Island East; Mulberry Island West; New Harbor Islands; North Islands; Oak Mound Bayou; Oyster Bayou; Pass A Loutre East; Pass A Loutre West; Pass du Bois; Pass Tante Phine; Pecan Island; Pelican Pass; Peveto Beach; Pilottown; Plumb Bayou;
Point Au Fer; Point Au Fer NE; Point Chevreuil; Point Chicot; Port Arthur South; Port Sulphur; Pte. Aux Marchuttes; Proctor Point; Pumpkin Islands; Redfish Point; Rollover Lake; Sabine Pass; Saint Joe Pass; Smith Bayou; South of South Pass; South Pass; Stake Islands; Taylor Pass; Texas Point; Three Mile Bay; Tigre Lagoon; Timbalier Island; Triumph; Venice; Weeks; West of Johnson Bayou; Western Isles Dernieres; Wilkinson Bay; Yscloskey.

Mississippi (1:24,000 scale): Bay Saint Louis; Biloxi; Cat Island; Chandeleur Light; Deer Island; Dog Keys Pass; English Lookout; Gautier North; Gautier South; Grand Bay SW; Gulfport North; Gulfport NW; Gulfport South; Horn Island East; Horn Island West; Isle Au Pitre; Kreole; Ocean Springs; Pascagoula North; Pascagoula South; Pass Christian; Petit Bois Island; Saint Joe Pass; Ship Island; Waveland.

Texas (1:24,000 scale): Allyns Bright; Anahuac; Aransas Pass; Austwell; Bacliff; Bayside; Big Hill Bayou; Brown Cedar Cut; Caplen; Carancahua Pass; Cedar Lakes East; Cedar Lakes West; Cedar Lane NE; Christmas Point; Clam Lake; Corpus Christi; Cove; Crane Islands NW; Crane Islands SW; Decros Point; Dressing Point; Estes; Flake; Freeport; Frozen Point; Galveston; Green Island; Hawk Island; High Island; Hitchcock; Hoskins Mound; Jones Creek; Keller Bay; Kleberg Point; La Comal; La Leona; La Parra Ranch NE; Laguna Vista; Lake Austin; Lake Como; Lake Stephenson; Lamar; Long Island; Los Amigos; Windmill; Maria Estella Well; Matagorda; Matagorda SW; Mesquite Bay; Mission Bay; Morgans Point; Mosquito Point; Mouth of Rio Grande; Mud Lake; North of Port Isabel NW; North of Port Isabel SW; Oak Island; Olivia; Oso Creek NE; Oyster Creek; Palacios; Palacios NE; Palacios Point; Palacios SE; Panther Point; Panther Point NE; Pass Cavallo SW; Pita Island; Point Comfort; Point of Rocks; Port Aransas; Port Arthur South; Port Bolivar; Port Ingleside; Port Isabel; Port Isabel NW; Port Lavaca East; Port Mansfield; Port O’Connor; Portland; Potrero Cortado; Potrero Lopeno NW; Potrero Lopeno SE; Potrero Lopeno SW; Rockport; Sabine Pass; San Luis Pass; Sargent; Sea Isle; Seadrift; Seadrift NE; Smith Point; South Bird Island; South Bird Island NW; South Bird Island SE; South of Palacios Point; South of Potrero Lopeno NE; South of Potrero Lopeno NW; South of Potrero Lopeno SE; South of Star Lake; St. Charles Bay; St. Charles Bay SE; St. Charles Bay SW; Star Lake; Texas City; Texas Point; The Jetties; Three Islands; Tivoli SE; Turtle Bay; Umbrella Point; Virginia Point; West of Johnson Bayou; Whites Ranch; Yarborough

Pass.

**PART 556—LEASING OF SULPHUR OR**
**OIL AND GAS IN THE OUTER**
**CONTINENTAL SHELF**

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

Sec. 556.0 Authority for information collection. 556.1 Purpose. 556.2 Policy. 556.4 Authority.

556.5 Definitions.

556.7 Cross references. 556.8 Leasing maps and diagrams.

556.10 Information to States.

556.11 Helium. 556.12 Supplemental sales.

**Subpart B—Oil and Gas Leasing Program**

556.16 Receipt and consideration of nominations; public notice and participation. 556.17 Review by State and local governments and other persons.

556.19 Periodic consultation with interested parties.

556.20 Consideration of coastal zone
management program.

**Subpart C—Reports From Federal Agencies**

556.22 General.

**Subpart D—Call for Information and**

**Nominations**

556.23 Information on areas.

556.25 Areas near coastal States.

**Subpart E—Area Identification and Tract**

**Size**

556.26 General.

556.28 Tract size.

**Subpart F—Lease Sales**

556.29 Proposed notice of sale.

556.31 State comments.
556.32 Notice of sale.

**Subpart G—Issuance of Leases**

556.35 Qualifications of lessees.

556.37 Lease term. 556.38 Joint bidding provisions.

556.40 Definitions. 556.41 Joint bidding requirements. 556.43 Chargeability for production.


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556.44 Bids disqualified.

556.46 Submission of bids.

556.47 Award of leases.

556.49 Lease form. 556.50 Dating of leases.

**Subpart H—Rentals and Royalties [Reserved]** 

**Subpart I—Bonding**

556.52 Bond requirements for an oil and gas or sulphur lease.

556.53 Additional bonds. 556.54 General requirements for bonds. 556.55 Lapse of bond. 556.56 Lease-specific abandonment

accounts. 556.57 Using a third-party guarantee

instead of a bond. 556.58 Termination of the period of liability and cancellation of a bond.

556.59 Forfeiture of bonds and/or other

securities.

**Subpart J—Assignments, Transfers, and**

**Extensions**

556.62 Assignment of lease or interest in

lease.

556.63 Service fees.

556.64 How to file transfers. 556.65 Attorney General review. 556.67 Separate filings for assignments. 556.68 Effect of assignment of a particular

tract. 556.70 Extension of lease by drilling or well reworking operations. 556.71 Directional drilling. 556.72 Compensatory payments as production.

**Subpart K—Termination of Leases**

556.76 Relinquishment of leases or parts of

leases.

556.77 Cancellation of leases.

**Subpart L—Section 6 Leases**

556.79 Effect of regulations on lease.

556.80 Leases of other minerals.

**Subpart M—Studies**

556.82 Environmental studies.

**Subpart N—Bonus or Royalty Credits for Exchange of Certain Leases Offshore** 

**Florida**

556.90 Which leases may I exchange for a bonus or royalty credit? 556.91 How much bonus or royalty credit will BOEM grant in exchange for a lease?

556.92 What must I do to obtain a bonus or royalty credit? 556.93 How is the bonus or royalty credit allocated among multiple lease owners? 556.94 How may I use the bonus or royalty

credit? 556.95 How do I transfer a bonus or royalty credit to another person?

Appendix to Part 556—Oil and Gas Cash

Bonus Bid

Authority: 31 U.S.C. 9701, 42 U.S.C. 6213, 43 U.S.C. 1334, Pub. L. 109–432. **Subpart A—Outer Continental Shelf Oil, Gas, and Sulphur Management,** 
**General**

**§ 556.0 Authority for information**

**collection.**

(a) The Office of Management and Budget (OMB) has approved the information collection requirements in this part under 44 U.S.C. 3501 et seq. OMB assigned the control number
1010–0006. The title of this information collection is ‘‘30 CFR part 556, Leasing of Sulphur or Oil and Gas in the Outer
Continental Shelf.’’

(b) BOEM collects this information to determine if the applicant filing for a
lease on the Outer Continental Shelf is qualified to hold such a lease. Response is required to obtain a benefit according

to 43 U.S.C. 1331 et seq. BOEM will protect proprietary information collected according to section 26 of the
OCS Lands Act and 30 CFR 556.10.

(c) An agency may not conduct or sponsor, and a person is not required to respond to a collection of information unless it displays a currently valid OMB
control number.

(d) Send comments regarding any aspect of the collection of information under this part, including suggestions for reducing the burden, to the
Information Collection Clearance Officer, Bureau of Ocean Energy Management, 381 Elden Street, Herndon, VA 20170.

**§ 556.1 Purpose.**

The purpose of the regulations in this part is to establish the procedures under which the Secretary of the Interior (Secretary) will exercise the authority to administer a leasing program for oil, gas and sulphur. The procedures under which the Secretary will exercise the authority to administer a program to grant rights-of-use and easements are addressed in other parts.

**§ 556.2 Policy.**

The management of Outer Continental
Shelf resources is to be conducted in accordance with the findings, purposes and policy directions provided by the
Outer Continental Shelf Lands Act Amendments of 1978 (43 U.S.C. 1332, 1801, 1802), and other Executive, legislative, judicial and Departmental guidance. The Secretary of the Interior
shall consider available environmental information in making decisions affecting Outer Continental Shelf

resources.

**§ 556.4 Authority.**

The Outer Continental Shelf Lands Act (OCSLA) (43 U.S.C. 1331 et seq. ) authorizes the Secretary of the Interior to issue, on a competitive basis, leases for oil and gas, and sulphur, in submerged lands of the outer Continental Shelf (OCS). The Actauthorizes 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


### 64684 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

from the Outer Continental Shelf and transported directly to such State by means of vessels or by a combination of means including vessels;

(4) Which is designated by the Secretary as a State in which there is a substantial probability of significant impact on or damage to the coastal, marine, or human environment, or a State in which there will be significant changes in the social, governmental, or economic infrastructure, resulting from the exploration, development, and production of oil and gas anywhere on the Outer Continental Shelf; or

(5) In which the Secretary finds that because of such activity there is, or will be, a significant risk of serious damage, due to factors such as prevailing winds and currents, to the marine or coastal environment in the event of any oilspill, blowout, or release of oil or gas from vessels, pipelines, or other transshipment facilities;

(h) Marine environment means the physical, atmospheric, and biological components, conditions, and factors which interactively determine the productivity, state, conditions, and quality of the marine ecosystem, including the waters of the high seas, the contiguous zone, transitional and intertidal areas, salt marshes, and
wetlands within the coastal zone and on the Outer Continental Shelf;

(i) Coastal environment means the physical, atmospheric, and biological components, conditions, and factors which interactively determine the productivity, state, conditions, and quality of the terrestrial ecosystem from
the shoreline inward to the boundaries of the coastal zone;

(j) Human environment means the physical, social, and economic components, conditions, and factors which interactively determine the state, condition, and quality of living conditions, employment, and health of those affected, directly or indirectly, by activities occurring on the Outer Continental Shelf;

(k) Mineral means oil, gas, and sulphur; it includes sand and gravel and salt used to facilitate the development and production of oil, gas, or sulphur.

(l) Authorized officer means any person authorized by law or by delegation of authority to or within BOEM to perform the duties described in this part.

(m) Bonus or royalty credit means a legal instrument or other written documentation, or an entry in an account managed by the Secretary that a bidder or lessee may use in lieu of any other monetary payment for—

(1) A bonus due for a lease on the Outer Continental Shelf; or (2) A royalty due on oil or gas production from any lease located on
the Outer Continental Shelf.

(n) Central planning area means the Central Gulf of Mexico Planning Area of the Outer Continental Shelf, as designated in the document entitled ‘‘Draft Proposed Program Outer Continental Shelf Oil and Gas Leasing Program 2007–2012,’’ dated February

2006.

(o) Coastline means the line of ordinary low water along that portion of the coast in direct contact with the open sea and the line marking the seaward
limit of inland waters.

(p) Desoto Canyon OPD means the official protraction diagram designated as Desoto Canyon which has a western edge located at the universal transverse mercator (UTM) X coordinate 1,346,400
in the North American Datum of 1927 (NAD 27).

(q) Destin Dome OPD means the official protraction diagram designated
as Destin Dome which has a western edge located at the universal transverse mercator (UTM) X coordinate 1,393,920
in the NAD 27.

(r) Eastern planning area means the Eastern Gulf of Mexico Planning Area of the Outer Continental Shelf, as designated in the document entitled ‘‘Draft Proposed Program Outer Continental Shelf Oil and Gas Leasing Program 2007–2012,’’ dated February

2006.

(s) Pensacola OPD means the official protraction diagram designated as Pensacola which has a western edge
located at the universal transverse mercator (UTM) X coordinate 1,393,920
in the NAD 27.

**§ 556.7 Cross references.**

(a) For Bureau of Ocean Energy Management regulations governing exploration, development and production on leases, see 30 CFR parts
550 and 570.

(b) For BOEM regulations governing the appeal of an order or decision issued under the regulations in this part, see 30 CFR part 590.

(c) For multiple use conflicts, see the Environmental Protection Agency listing of ocean dumping sites—40 CFR
part 228.

(d) For related National Oceanic and Atmospheric Administration programs

see:

(1) Marine sanctuary regulations, 15 CFR part 922;

(2) Fishermen’s Contingency Fund, 50 CFR part 296;

(3) Coastal Energy Impact Program, 15 CFR part 931;

(e) For Coast Guard regulations on the oil spill liability of vessels and operators, see 33 CFR parts 132, 135,
and 136.

(f) For Coast Guard regulations on port access routes, see 33 CFR part 164.

(g) For compliance with the National Environmental Policy Act, see 40 CFR parts 1500 through 1508.

(h) For Department of Transportation regulations on offshore pipeline facilities, see 49 CFR part 195.

(i) For Department of Defense regulations on military activities on offshore areas, see 32 CFR part 252.

**§ 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.**

(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. (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 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** 

**§ 556.22 General.**

For oil and gas lease sales shown in an approved leasing schedule and as the need arises for other mineral leasing, the Director shall prepare a report describing the general geology and potential mineral resources of the area under consideration. The Director may request other interested Federal Agencies to prepare reports describing, to the extent known, any other valuable resources contained within the general area and the potential effect of mineral operations upon the resources or upon the total environment or other uses of
the area.

**Subpart D—Call for Information and**

**Nominations**

**§ 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 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.

**§ 556.32 Notice of sale.**

(a) Upon approval of the Secretary, the Director shall publish the notice of
lease sale in the Federal Register as the official publication, and may publish the notice in other publications. The publication in the Federal Register shall be at least 30 days prior to the date of the sale. The notice shall state the place and time at which bids shall be filed, and the place, date and hour at which bids shall be opened. The notice shall contain or reference a description of the areas to be offered for lease and any stipulations, terms and conditions of the
sale.

(b) Tracts shall be offered for lease by competitive sealed bidding under conditions specified in the notice of
lease sale and in accordance with all applicable laws and regulations. A suggested format for bidder submissions appears in the appendix to this part.

(c) The notice of lease sale shall
contain a reference to the OCS lease
form which shall be issued to successful
bidders.

(d) With the approval of the Secretary, the Director may defer any part of the payment of the cash bonus according to
a schedule announced at the time of the notice of lease sale. Payment shall be made no later than 5 years after the date
of the lease sale. The schedule shall contain provisions for guaranteed payment of a deferred bonus.

(e) In order to obtain statistical information to determine which bidding alternatives best accomplish the purposes and policies of the Act, the Director may, until September 18, 1983, require each bidder to submit bids for any OCS area in accordance with more than one of the bidding systems described in section 8(a)(1) of the Act. No more than 10 percent of the tracts offered each year shall contain such a requirement. Leases may be awarded using a bidding alternative selected at random for statistical purposes, if it is otherwise consistent with the purposes and policies of the Act.

**Subpart G—Issuance of Leases**

**§ 556.35 Qualifications of lessees.**

(a) In accordance with section 8 of the Act, leases shall be awarded only to the highest responsible qualified bidder.

(b) Mineral leases issued pursuant to section 8 of the Act may be held only by:

(1) Citizens and nationals of the United States;

(2) Aliens lawfully admitted for permanent residence in the United States as defined in 8 U.S.C. 1101(a)(20);

(3) Private, public or municipal corporations organized under the laws of the United States or of any State or of the District of Columbia or territory thereof; or

(4) Associations of such citizens, nationals, resident aliens, or private, public, or municipal corporations, States, or political subdivisions of

States.

(c) BOEM may disqualify you from acquiring any new lease holdings or lease assignments if your operating performance is unacceptable according

to 30 CFR 550.135.

**§ 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,


### 64688 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

production of crude oil, natural gas, or liquefied petroleum products and shall include, but not be limited to, a royalty interest, or overriding royalty interest, whether payable in cash or in kind, a working interest, a net profits interest, a production payment, or a carried

interest.

(g) Liquefied petroleum products means natural gas liquid products including the following: ethane, propane, butane, pentane, natural gasoline, and other natural gas products recovered by a process of absorption, adsorption, compression, or refrigeration cycling, or a combination of such processes.

(h) Natural gas means a mixture of hydrocarbons and varying quantities of nonhydrocarbons that exist in the gaseous phase.

(i) Oil and gas lease means an oil and gas lease either offered or issued pursuant to the provisions of the Act.

(j) Owned means: (1) With respect to crude oil —having
either an economic interest in or a power of disposition over the production of crude oil;

(2) With respect to natural gas

— having either an economic interest in or a power of disposition over the production of natural gas; and

(3) With respect to liquefied petroleum products—having either an economic interest in or a power of disposition over any liquefied petroleum product at the time of completion of the liquefaction process.

(k) Prior production period means the continuous 6-month period of January 1 through June 30 preceding November 1 through April 30 for joint bids submitted during the 6-month bidding period from November 1 through April 30, and means the continuous 6-month period of July 1 through December 31 preceding May 1 through October 31 for joint bids submitted during the 6-month bidding period from May 1 through
October 31.

(l) Production: (1) Of crude oil means the volume of crude oil produced worldwide from reservoirs during the prior production period. The amount of such crude oil production shall be established by measurement of volumes delivered at the point of custody transfer ( e.g., from storage tanks to pipelines, trucks, tankers, or other media for transport to refineries or terminals) with adjustments for:

(i) Net differences between opening and closing inventories, and

(ii) Basic sediment and water; (2) Of natural gas means the volume of natural gas produced worldwide from natural oil and gas reservoirs during the prior production period, with adjustments, where applicable, to reflect

(i) The volume of gas returned to natural reservoirs; and

(ii) The reduction of volume resulting from the removal of natural gas liquids and nonhydrocarbon gases.

(3) Of liquefied petroleum products mean the volume of natural gas liquids produced from reservoir gas and liquefied at surface separators, field facilities, or gas processing plants worldwide during the prior production period; these liquefied petroleum products include the following:

(i) Condensate—natural gas liquids recovered from gas well gas (associated and non-associated) in separators or field facilities;

(ii) Gas plant products—natural gas liquids recovered from natural gas in gas processing plants and from field facilities. Gas plant products shall include the following as classified according to the standards of the
Natural Gas Processors Association (NGPA) or the American Society for Testing and Materials (ASTM):

(A) Ethane—C 2H 6 (B) Propane—C 3 H 8 (C) Butane—C 4H 10 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 6- month bidding period, and who was chargeable for the prior production period with an average daily production
in excess of 1.6 million barrels of crude oil, natural gas and liquefied petroleum products, shall have filed under oath with the Director, a Statement of Production of crude oil, natural gas and liquefied petroleum products,
hereinafter referred to as a Statement of Production, no later than 45 days prior to the commencement of the applicable 6-month bidding period of May 1 through October 31, and November 1 through April 30. Statements of
Production shall be submitted to the Director, BOEM (Attention: Offshore Leasing Management Division), Washington, DC 20240. The Statement
of Production shall indicate that the person was chargeable, in accordance with § 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


### 64689 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

exploration and development will not
occur on such lands unless the exemption is granted.

**§ 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 inany 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 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 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


### 64690 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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 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. (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**

**§ 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 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 (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


### 64692 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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 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: (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 mayauthorize 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.


### 64693 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

(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. TheRegional 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: (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 accou ntant containing the accountant’s audit opinion or review opinion of the statements. The report must be prepared in conformance with generally accepted accounting principles and contain no adverse opinion. (ii) Financial statements for completed quarters in the current fiscal

year, Your guarantor’s financial officer certifies to be correct.

(iii) Additional information as requested by the Regional Director, Your guarantor’s financial officer certifies to be correct.

(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 days, sufficient funds for the Regional Director to complete corrective action.

(2) If your guarantor complies with paragraph (d)(1) of this section, this compliance will not reduce its liability.

(3) If your guarantor wishes to terminate the period of liability under its guarantee, it must:

(i) Notify you and the Regional Director at least 90 days before the proposed termination date; (ii) Obtain the Regional Director’s approval for the termination of the period of liability for all or a specified portion of your guarantor’s guarantee;
and

(iii) Remain liable for all work and workmanship performed during the period that your guarantor’s guarantee is
in effect.

(4) You must provide a suitable replacement security instrument before


### 64694 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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:

For the following type of bond The period of liability will end Your bond will be cancelled . . .

(1) Base bonds submitted under § 556.52(a),

§ 556.53(a), or (b), When the Regional Director determines that you have met all of your obligations under the lease, Seven years after the termination of thelease, 6 years after completion of all bonded obligations, or at the conclusion of any appeals or litigation related to your bondedobligation, whichever is the latest. The Regional Director will reduce the amount ofyour bond or return a portion of your security if the Regional Director determines that you need less than the full amount of the base bond to meet any possible future problems. (2) Supplemental bonds submitted under

§ 556.53(d), When the Regional Director determines that you have met all your obligations covered by the supplemental bond, When you meet your bonded obligations, unless the Regional Director:

(i) Determines that the future potential liability

resulting from any undetected problems is greater than the amount of the base bond;

and


### 64695 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

For the following type of bond The period of liability will end 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.

**§ 556.59 Forfeiture of bonds and/or other**

**securities.**

This section explains how a bond or other security may be forfeited.

(a) The Regional Director will call for forfeiture of all or part of the bond, other form of security, or guarantee you provide under this part if:

(1) You (the party who provided the bond) refuse, or the Regional Director determines that you are unable, to comply with any term or condition of your lease; or

(2) You default under one of the conditions under which the Regional Director accepts your bond, third-party guarantee, and/or other form of security.

(b) The Regional Director may pursue forfeiture of your bond without first making demands for performance against any lessee, operating rights owner, or other person authorized to perform lease obligations.

(c) The Regional Director will: (1) Notify you, the surety on your bond or other form of security, and any third-party guarantor, of his/her
determination to call for forfeiture of the bond, security, or guarantee under this

section.

(i) This notice will be in writing and will provide the reasons for the
forfeiture and the amount to be
forfeited.

(ii) The Regional Director must base
the amount he/she determines is forfeited upon his/her estimate of the total cost of corrective action to bring your lease into compliance.

(2) Advise you, your third-party guarantor, and any surety, that you, your guarantor, and any surety may avoid forfeiture if, within 5 working days:

(i) You agree to, and demonstrate that you will, bring your lease into compliance within the timeframe that the Regional Director prescribes;

(ii) Your third-party guarantor agrees to, and demonstrates that it will, complete the corrective action to bring your lease into compliance within the timeframe that the Regional Director prescribes; or

(iii) Your surety agrees to, and demonstrates that it will, bring your lease into compliance within the timeframe that the Regional Director prescribes, even if the cost of compliance exceeds the face amount of the bond or other surety instrument.

(d) If the Regional Director finds you are in default, he/she may cause the forfeiture of any bonds and other security deposited as your guarantee of compliance with the terms and conditions of your lease and the regulations in this chapter.

(e) If the Regional Director determines that your bond and/or other security is forfeited, the Regional Director will:

(1) Collect the forfeited amount; and (2) Use the funds collected to bring your leases into compliance and to correct any default.

(f) If the amount the Regional Director collects under your bond and other security is insufficient to pay the full cost of corrective actions he/she may:

(1) Take or direct action to obtain full compliance with your lease and the regulations in this chapter; and

(2) Recover from you, any co-lessee, operating rights owner, and/or any third-party guarantor responsible under this subpart all costs in excess of the amount he/she collects under your forfeited bond and other security.

(g) The amount that the Regional Director collects under your forfeited bond and other security may exceed the costs of taking the corrective actions required to obtain full compliance with the terms and conditions of your lease and the regulations in this chapter. In this case, the Regional Director will return the excess funds to the party from whom they were collected. **Subpart J—Assignments, Transfers,**

**and Extensions**

**§ 556.62 Assignment of lease or interest in**

**lease.**

This section explains how to assign
record title and other interests in OCS oil and gas or sulphur leases.

(a) BOEM may approve the assignment to you of the ownership of the record title to a lease or any undivided interest in a lease, or an officially designated subdivision of a lease, only if:

(1) You qualify to hold a lease under § 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


### 64696 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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.



### S ERVICE 

### F EE 

### TABLE

Service Fee amount 30 CFR citation

(1) Record Title/Operating Rights (Transfer) ................................................................................... ..................... $186 § 556.64 (2) Non-required Document Filing ............................................................................................... ......................... 27 § 556.64

(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.

**§ 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. (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 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:


### 64697 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

(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.

**§ 556.68 Effect of assignment of a particular tract.** 

(a) When an assignment is made of all the record title to a portion of the acreage in a lease, the assigned and retained portions become segregated into separate and distinct leases. In such a case, the assignee becomes a lessee of the Government as to the segregated tract that is the subject of assignment, and is bound by the terms of the lease as though the lease had been obtained from the United States in the assignee’s own name, and the assignment, after its approval, shall be the basis of a new record. Royalty, minimum royalty and rental provisions of the original lease shall apply separately to each segregated portion.

(b) For assignments of a portion of an oil and gas lease approved after the effective date of this section, each segregated lease shall continue in full force and effect for the primary term of the original lease and so long thereafter as oil or gas is produced from that segregated portion of the leased area in paying quantities or drilling or well reworking operations as approved by the Secretary are conducted.

(c) For those assignments approved prior to the effective date of this section, each segregated lease shall continue in full force and effect for the primary term of the original lease and so long thereafter as oil and gas may be produced from the original leased area in paying quantities or drilling or well reworking operations, as approved by the Secretary, are conducted.

**§ 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 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.


### 64698 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and 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.

**§ 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**

**§ 556.82 Environmental studies.**

(a) The Director shall conduct a study of any area or region included in any
lease sale in order to establish
information needed for assessment and management of impacts on the human,
marine and coastal environments which may be affected by OCS oil and gas activities in such area or region. Any study shall, to the extent practicable, be designed to predict environmental impacts of pollutants introduced into the environments and of the impacts of
offshore activities on the seabed and
affected coastal areas.

(b) Studies shall be planned and carried out in cooperation with the affected States and interested parties and, to the extent possible, shall not duplicate studies done under other laws. Where appropriate, the Director shall, to the maximum extent practicable, enter into agreements with the National Oceanic and Atmospheric Administration in executing the environmental studies responsibilities. By agreement, the Director may also utilize services, personnel or facilities of any Federal, State or local government agency in the conduct of such study.

(c) Any study of an area or region required by paragraph (a) of this section
for a lease sale shall be commenced not later than 6 months prior to holding a lease sale for that area. The Director may utilize information collected in any prior study. The Director may initiate studies for areas or regions not identified in the leasing program.

(d) After the leasing and developing of any area or region, the Director shall
conduct such studies as are deemed necessary to establish additional
information and shall monitor the human, marine and coastal environments of such area or region in a manner designed to provide information which can be compared
with the results of studies conducted prior to OCS oil and gas development. This shall be done to identify any significant changes in the quality and productivity of such environments, to establish trends in the areas studies, and to design experiments identifying the causes of such changes. Findings from
such studies shall be used to recommend modifications in practices which are employed to mitigate the
effects of OCS activities and to enhance the data/information base for predicting impacts which might result from a single lease sale or cumulative OCS

activities.

(e) Information available or collected by the studies program shall, to the extent practicable, be provided in a form
and in a timeframe that can be used in the decision-making process associated with a specific leasing action or with longer term OCS minerals management responsibilities.

**Subpart N—Bonus or Royalty Credits for Exchange of Certain Leases** 
**Offshore Florida**

**§ 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. **§ 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: (1) The effective date of the transfer,

(2) The OCS–G number for the lease that originally qualified for the credit,

(3) The amount of the credit being transferred,

(4) Company names punctuated exactly as filed on the qualification card at BOEM, and

(5) A corporate seal, if you used a corporate seal in your initial qualification to hold OCS leases. (d) The transferee of a credit transferred under this section may use it in accordance with § 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:

Tract No.* Total amount bid 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.

Bidder qualification No. Proportionate interest of company(s) submitting bid Name and address of bidding company

ll Misc. No.

llllllllllllllllllll,

Authorized signatory’s name and title.

**PART 559—MINERAL LEASING:**
**DEFINITIONS**

Sec. 559.001 Purpose and scope.

559.002 Definitions.

Authority: Pub. L. 83–212, 67 Stat. 462, 43

U.S.C. 1331 et seq., as amended by Pub. L.
95–372, 92 Stat. 629.

**§ 559.001 Purpose and scope.**

The purpose of this part 559 is to define various terms appearing in part

560.

**§ 559.002 Definitions.**

For purposes of part 560:

Area or region means the geographic area or region over which the BOEM designated official has jurisdiction,
unless the context in which those words
are used indicates that a different meaning is intended.

BOEM means Bureau of Ocean Energy Management.

Designated official means a representative of DOI subject to the direction and supervisory authority of the Directors, BOEM, and the appropriate Regional Manager of the BOEM authorized and empowered to supervise and direct all oil and gas operations and to perform other duties prescribed in this chapter.

Director means Director, BOEM, DOI.

DOI means the Department of the Interior, including the Secretary of the Interior, or his or her delegate.

Federal lease means an agreement which, for any consideration, including, but not limited to, bonuses, rents or royalties conferred, and convenants to be observed, authorizes a person to explore for, or develop, or produce (or to do any or all of these) oil and gas, coal, oil shale, tar sands, and geothermal
resources on lands or interests in lands under Federal jurisdiction.

Gas means natural gas as defined by the Federal Energy Regulatory

Commission.

OCS means the Outer Continental Shelf, which includes all submerged lands (1) that lie seaward outside of the area of lands beneath navigable waters as defined in the Submerged Lands Act (Pub. L. 31–35, 67 Stat. 29, (43 U.S.C. 1301)) and (2) of which the subsoil and seabed appertain to the United States are subject to its jurisdiction and
control.

OCSLA means the Outer Continental Shelf Lands Act, as amended (Act of August 7, 1953, Ch. 345, 67 Stat. 462,

43 U.S.C. 1331 et seq., as amended by Pub. L. 95–372, 92 Stat. 629).

Oil means a mixture of hydrocarbons that exists in a liquid or gaseous phase in an underground reservoir and which remains or becomes liquid at atmospheric pressure after passing through surface separating facilities, including condensate recovered by means other than a manufacturing

process.

**PART 560—OUTER CONTINENTAL**
**SHELF OIL AND GAS LEASING**

**Subpart A—General Provisions**

Sec. 560.1 What is the purpose of this part? 560.2 What definitions apply to this part? 560.3 What is BOEM’s authority to collect

information? **Subpart B—Bidding Systems**

General Provisions

560.101 What is the purpose of this subpart? 560.102 What definitions apply to this subpart? 560.110 What bidding systems may BOEM

use? 560.111 What conditions apply to the bidding systems that BOEM uses?

Eligible Leases

560.112 How do royalty suspension volumes apply to eligible leases? 560.113 When does an eligible lease qualify for a royalty suspension volume? 560.114 How does BOEM assign and monitor royalty suspension volumes for eligible leases? 560.115 How long will a royalty suspension volume for an eligible lease be effective? 560.116 How do I measure natural gas production on my eligible lease?

Royalty Suspensions (RS) Leases

560.120 How does royalty suspension apply

to leases issued in a sale held after

November 2000?

560.121 When does a lease issued in a sale held after November 2000 get a royalty suspension? 560.122 How long will a royalty suspension

volume be effective for a lease issued in

a sale held after November 2000? 560.123 How do I measure natural gas production for a lease issued in a sale

held after November 2000? 560.124 How will royalty suspension apply if BOEM assigns a lease issued in a sale

held after November 2000 to a field that has a pre-Act lease?

Bidding System Selection Criteria

560.130 What criteria does BOEM use for selecting bidding systems and bidding system components?


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**Subpart C—[Reserved]**

**Subpart D—Joint Bidding**

560.301 What is the purpose of this subpart? 560.302 What definitions apply to this subpart? 560.303 What are the joint bidding requirements?

Authority: 43 U.S.C. 1331 et seq.

**Subpart A—General Provisions**

**§ 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?**

(a) The Paperwork Reduction Act of 1995 (PRA) requires us to inform you that we may not conduct or sponsor, and you are not required to respond to,
a collection of information unless it displays a currently valid OMB control
number. The information collection under 30 CFR part 560 is either exempt from the PRA (5 CFR 1320.4(a)(2), (c)) or refers to requirements covered under 30 CFR parts 203 and 556.

(b) You may send comments regarding any aspect of the collection of information under this part to the
Information Collection Clearance Officer, Bureau of Ocean Energy Management, 381 Elden Street, Herndon, VA 20170. **Subpart B—Bidding Systems**

General Provisions

**§ 560.101 What is the purpose of this subpart?** 

This subpart establishes the bidding systems that we may use to offer and sell Federal leases for the exploration, development, and production of oil and gas resources located on the OCS.

**§ 560.102 What definitions apply to this subpart?** 

Act means the Outer Continental Shelf Deep Water Royalty Relief Act, Pub. L. 104–58, 43 U.S.C. 1337(3).

Eligible lease means a lease that: (1) Is issued as part of an OCS lease sale held after November 28, 1995, and before November 28, 2000;

(2) Is located in the Gulf of Mexico in water depths of 200 meters or deeper;

(3) Lies wholly west of 87 degrees, 30 minutes West longitude; and

(4) Is offered subject to a royalty suspension volume.

Field means an area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same general geological structural feature and/or stratigraphic trapping condition. Two or more reservoirs may be in a field, separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both.

Highest responsible qualified bidder means a person who has met the appropriate requirements of 30 CFR part 556, subpart G, and has submitted a bid higher than any other bids by qualified
bidders on the same tract.

Highest royalty rate means the highest percent rate payable to the United States, as specified in the lease, in the amount or value of the production saved, removed, or sold.

Lease period means the time from lease issuance until relinquishment, expiration, or termination.

Lowest royalty rate means the lowest percent rate payable to the United States, as specified in the lease, in the amount or value of the production saved, removed, or sold.

OCS lease sale means the Department of the Interior (DOI) proceeding by
which leases for certain OCS tracts are offered for sale by competitive bidding and during which bids are received, announced, and recorded.

Pre-Act lease means a lease that: (1) Is issued as part of an OCS lease sale held before November 28, 1995;

(2) Is located in the Gulf of Mexico in water depths of 200 meters or deeper;
and

(3) Lies wholly west of 87 degrees, 30 minutes West longitude (see 30 CFR part 203).

Production period means the period during which the amount of oil and gas produced from a tract (or, if the tract is unitized, the amount of oil and gas as allocated under a unitization formula) will be measured for purposes of determining the amount of royalty payable to the United States.

Qualified bidder means a person who has met the appropriate requirements of 30 CFR part 556, subpart G.

Royalty rate means the percentage of the amount or value of the production saved, removed, or sold that is due and payable to the United States

Government.

Royalty suspension (RS) lease means a lease that:

(1) Is issued as part of an OCS lease sale held after November 28, 2000;

(2) Is in locations or planning areas specified in a particular Notice of OCS Lease Sale; and

(3) Is offered subject to a royalty suspension specified in a Notice of OCS Lease Sale published in the Federal Register

.

Tract means a designation assigned solely for administrative purposes to a
block or combination of blocks that are identified by a leasing map or an official protraction diagram prepared by the

DOI.

Value of production means the value of all oil and gas production saved, removed, or sold from a tract (or, if the tract is unitized, the value of all oil and gas production saved, removed, or sold
and credited to the tract under a unitization formula) during a period of production. The value of production is determined under 30 CFR part 1206.

**§ 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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For the bidding system . . . The bid variable is the . . . And the characteristics are . . .

(b) Royalty rate bid with fixed cash

bonus, Royalty rate, 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 F EDERAL R EGISTER

. (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, (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**

. (d) Cash bonus bid with fixed share

of the net profits of no less than 30 percent, Cash bonus, (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**

.(e) Cash bonus with variable royalty rate(s) during one or more periods of production, Cash bonus, (1) We may suspend or defer royalty for a period, volume, or value ofproduction. Notwithstanding suspensions or deferrals, we may impose a minimum royalty. The suspensions or deferrals may vary based on prices or price changes of oil and/or gas. (2) You may pay a royalty rate less than 12.5 percent on production

but not less than zero percent. (3) We will specify the applicable royalty rates(s) and suspension or

deferral magnitudes, formulas, or relationships in the Notice of OCS Lease Sale published in the **Federal Register**

. (f) Cash bonus with royalty rate(s)

based on formula(s) or schedule(s) during one or more periods of production, Cash bonus, We will base the royalty rate on formula(s) or schedule(s) specified in the Notice of OCS Lease Sale published in the F EDERAL R EGISTER

.

(g) Cash bonus with a fixed royalty

rate of not less than 12.5 percent, at the beginning of thelease 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, 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**

.

**§ 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 the Notice of OCS Lease Sale published
in the Federal Register

.

(c) For the bidding systems listed in this subpart, if the bid variable is a cash bonus bid, the highest bid by a qualified
bidder determines the amount of cash bonus to be paid. We will include the minimum bid level(s) in the Notice of OCS Lease Sale published in the Federal Register

.

(d) For the bidding systems listed in this subpart, if the bid variable is the royalty rate, the highest bid by a qualified bidder determines the royalty rate to be paid. We will include the minimum royalty rate(s) in the Notice of OCS Lease Sale published in the Federal Register

.

(e) We may, by rule, add to or modify the bidding systems listed in § 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.

**§ 560.113 When does an eligible lease qualify for a royalty suspension volume?** 

(a) Your eligible lease will receive a royalty suspension volume as specified in the Act. The bidding system in § 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.

**§ 560.114 How does BOEM assign and monitor royalty suspension volumes for**  **eligible leases?**

(a) We have specified the water depth category for each eligible lease in the final Notice of OCS Lease Sale Package. The Final Notice of Sale is published in
the Federal Register and the complete Final Notice of OCS Lease Sale Package
is available on the BOEM Web site. Our determination of water depth for each
lease became final when we issued the
lease.

(b) We have specified in the Notice of OCS Lease Sale the royalty suspension volume applicable to each water depth. The following table shows the royalty suspension volumes for each eligible lease in million barrels of oil equivalent (MMBOE):

Water depth Minimum royalty suspension volume

(1) 200 to less than

400 meters. 17.5 MMBOE.

(2) 400 to less than

800 meters. 52.5 MMBOE.

(3) 800 meters or more 87.5 MMBOE.

**§ 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 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?**

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.

**§ 560.121 When does a lease issued in a sale held after November 2000 get a royalty**  **suspension?**

(a) We will specify any royalty suspension for your RS lease in the Notice of OCS Lease Sale published in
the Federal Register for the sale in which you acquire the RS lease and will repeat it in the lease document. In
addition:

(1) Your RS lease may produce royalty-free the royalty suspension we specify for your lease, even if the field to which we assign it is producing.

(2) The royalty suspension we specify in the Notice of OCS Lease Sale for your lease does not apply to any other leases in the field to which we assign your RS
lease.

(b) You may apply for a supplemental royalty suspension for a project under 30 CFR part 203, if your lease is located:

(1) In the Gulf of Mexico, in water 200 meters or deeper, and wholly west of 87 degrees, 30 minutes West longitude; or

(2) Offshore of Alaska. (c) Your RS lease retains the royalty suspension with which we issued it even if we deny your application for
more relief.

**§ 560.122 How long will a royalty suspension volume be effective for a lease** 

**issued in a sale held after November 2000?**

(a) The royalty suspension volume for your RS lease will continue through the
end of the month in which cumulative production from your lease reaches the applicable royalty suspension volume or the lease period ends.

(b)(1) Notwithstanding any royalty suspension volume under this subpart, you must pay royalty at the lease stipulated rate on:

(i) Any oil produced for any period stipulated in the lease during which the arithmetic average of the daily closing price on the New York Mercantile Exchange (NYMEX) for light sweet crude oil exceeds the applicable threshold price of $36.39 per barrel, adjusted annually after calendar year
2007 for inflation unless the lease terms prescribe a different price threshold.

(ii) Any natural gas produced for any period stipulated in the lease during which the arithmetic average of the daily closing price on the NYMEX for natural gas exceeds the applicable threshold price of $4.55 per MMBtu, adjusted annually after calendar year
2007 for inflation unless the lease terms prescribe a different price threshold.

(iii) Determine the threshold price for any calendar year after 2007 by adjusting the threshold price in the previous year by the percentage that the implicit price deflator for the gross domestic product, as published by the Department of Commerce, changed during the calendar year.

(2) You must pay any royalty due under this paragraph, plus late payment interest under 30 CFR 1218.54, no later than 90 days after the end of the period for which royalty is owed.

(3) Any production on which you must pay royalty under this paragraph will count toward the production volume determined under §§ 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


### 64703 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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

**§ 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; (c) Ensuring competent and safe operations;

(d) Avoiding undue speculation; (e) Avoiding unnecessary delays in exploration, development, and production;

(f) Discovering and recovering oil and

gas;

(g) Developing new oil and gas resources in an efficient and timely

manner;

(h) Limiting the administrative burdens on Government and industry;
and

(i) Providing an opportunity to experiment with various bidding systems to enable us to identify those most appropriate for the satisfaction of the objectives of the United States in
OCS lease sales.

**Subpart C—[Reserved]**

**Subpart D—Joint Bidding**

**§ 560.301 What is the purpose of this subpart?** 

The purpose of this subpart is to encourage participation in OCS oil and gas lease sales by limiting the requirement for filing ‘‘Statements of Production’’ to certain joint bidders.

**§ 560.302 What definitions apply to this subpart?** 

For the purposes of this subpart, all
terms used are defined as in 30 CFR

556.40.

**§ 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 6- month bidding period with any other person similarly chargeable. We will disqualify and reject these bids. (d) If your average daily production in the prior production period met or exceeded the quantities specified in paragraph (a) of this section, you may not enter into an agreement prior to a
lease sale that would result in two or more persons, similarly chargeable, acquiring or holding any interest in the
tract for which the bid is submitted. We will disqualify and reject these bids.

**PART 570—NONDISCRIMINATION IN**
**THE OUTER CONTINENTAL SHELF**

Sec. 570.1 Purpose. 570.2 Application of this part.

570.3 Definitions. 570.4 Discrimination prohibited. 570.5 Complaint.

570.6 Process.
570.7 Remedies.

Authority: 43 U.S.C. 1863.

**§ 570.1 Purpose.**

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

**§ 570.2 Application of this part.**

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

**§ 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,


### 64704 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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.

**§ 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 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.

**PART 580—PROSPECTING FOR MINERALS OTHER THAN OIL, GAS,** 
**AND SULPHUR ON THE OUTER**
**CONTINENTAL SHELF**

**Subpart A—General Information**

Sec. 580.1 What definitions apply to this part? 580.2 What is the purpose of this part? 580.3 What requirements must I follow when I conduct prospecting or research

activities? 580.4 What activities are not covered by this part?

**Subpart B—How To Apply for a Permit or**

**File a Notice**

580.10 What must I do before I may conduct prospecting activities? 580.11 What must I do before I may

conduct scientific research? 580.12 What must I include in my application or notification? 580.13 Where must I send my application

or notification?

**Subpart C—Obligations Under This Part**

Prohibitions and Requirements

580.20 What must I not do in conducting Geological and Geophysical (G&G) prospecting or scientific research? 580.21 What must I do in conducting G&G prospecting or scientific research? 580.22 What must I do when seeking approval for modifications? 580.23 How must I cooperate with inspection activities? 580.24 What reports must I file?

Interrupted Activities

580.25 When may BOEM require me to stop activities under this part? 580.26 When may I resume activities? 580.27 When may BOEM cancel my permit? 580.28 May I relinquish my permit?

Environmental Issues

580.29 Will BOEM monitor the environmental effects of my activity? 580.30 What activities will not require environmental analysis? 580.31 Whom will BOEM notify about

environmental issues?

Penalties and Appeals

580.32 What penalties may I be subject to? 580.33 How can I appeal a penalty? 580.34 How can I appeal an order or

decision?

**Subpart D—Data Requirements**

Geological Data and Information

580.40 When do I notify BOEM that geological data and information are available for submission, inspection, and

selection? 580.41 What types of geological data and

information must I submit to BOEM? 580.42 When geological data and information are obtained by a third party, what must we both do?

Geophysical Data and Information

580.50 When do I notify BOEM that geophysical data and information are available for submission, inspection, and

selection? 580.51 What types of geophysical data and

information must I submit to BOEM? 580.52 When geophysical data and information are obtained by a third party, what must we both do?

Reimbursement

580.60 Which of my costs will be

reimbursed? 580.61 Which of my costs will not be

reimbursed?

Protections

580.70 What data and information will be protected from public disclosure?

580.71 What is the timetable for release of

data and information? 580.72 What procedure will BOEM follow to disclose acquired data and

information to a contractor for reproduction, processing, and interpretation?
580.73 Will BOEM share data and

information with coastal States?

**Subpart E—Information Collection**

580.80 Paperwork Reduction Act

statement—information collection.

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

**Subpart A—General Information**

**§ 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 official authorized to act on the
Director’s behalf.

Geological and geophysical (G&G) prospecting activities mean the
commercial search for mineral resources other than oil, gas, or sulphur. Activities classified as prospecting include, but
are not limited to:

(1) Geological and geophysical marine and airborne surveys where magnetic, gravity, seismic reflection, seismic refraction, or the gathering through coring or other geological samples are used to detect or imply the presence of hard minerals; and

(2) Any drilling, whether on or off a geological structure.

Geological and geophysical (G&G) scientific research activities mean any investigations related to hard minerals
that are conducted on the OCS for
academic or scientific research. These investigations would involve gathering and analyzing geological, geochemical, or geophysical data and information that are made available to the public for inspection and reproduction at the earliest practical time. The term does
not include commercial G&G exploration or commercial G&G prospecting activities.

Geological data and information means data and information gathered through or derived from geological and geochemical techniques, e.g., coring and test drilling, well logging, bottom sampling, or other physical sampling or chemical testing process.

Geological sample means a collected portion of the seabed, the subseabed, or the overlying waters acquired while conducting prospecting or scientific
research activities.

Geophysical data and information means any data or information gathered through or derived from geophysical measurement or sensing techniques ( e.g., gravity, magnetic, or seismic).

Governor means the Governor of a State or the person or entity lawfully designated by or under State law to exercise the powers granted to a
Governor under the Act.

Hard minerals mean any minerals
found on or below the surface of the seabed except for oil, gas, or sulphur.

Interpreted geological information means the knowledge, often in the form of schematic cross sections, 3- dimensional representations, and maps, developed by determining the geological significance of geological data and analyzed and processed geologic
information.

Interpreted geophysical information means knowledge, often in the form of seismic cross sections, 3-dimensional representations, and maps, developed by determining the geological significance of geophysical data and processed geophysical information.

Lease means, depending upon the requirements of the context, either:

(1) An agreement issued under section
8 or maintained under section 6 of the Act that authorizes mineral exploration, development and production; or

(2) The area covered by an agreement specified in paragraph (1) of this
definition.

Material remains means physical evidence of human habitation, occupation, use, or activity, including the site, location, or context in which
evidence is situated.

Minerals mean all minerals authorized by an Act of Congress to be produced from ‘‘public lands’’ as
defined in section 103 of the Federal Land Policy and Management Act of 1976 (43 U.S.C. 1702). The termincludes 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.

**§ 580.2 What is the purpose of this part?**

The purpose of this part is to: (a) Allow you to conduct prospecting
activities or scientific research activities
on the OCS in Federal waters related to
hard minerals on unleased lands or on lands under lease to a third party.

(b) Ensure that you carry out prospecting activities or scientific
research activities in a safe and environmentally sound manner so as to prevent harm or damage to, or waste of, any natural resources (including any hard minerals in areas leased or not leased), any life (including fish and other aquatic life), property, or the marine, coastal, or human environment.

(c) Inform you and third parties of your legal and contractual obligations.

(d) Inform you and third parties of: (1) The U.S. Government’s rights to
access G&G data and information collected under permit on the OCS;

(2) Reimbursement we will make for data and information that are submitted;
and

(3) The proprietary terms of data and
information that we retain.

**§ 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; (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.) **§ 580.13 Where must I send my application**

**or notification?**

You must apply for a permit or file a notice at one of the following locations:

For the OCS off the . . . Apply to . . .

(a) State of Alaska .............................................. Regional Supervisor for Resource Evaluation, Bureau of Ocean Energy Management, Alaska OCS Region, 3801 Centerpoint Drive, Suite 500, Anchorage, AK 99503. (b) Atlantic Coast, Gulf of Mexico, Puerto Rico,

or U.S. territories in the Caribbean Sea. Regional Supervisor for Resource Evaluation, Bureau of Ocean Energy Management, Gulf of Mexico OCS Region, 1201 Elmwood Park Boulevard, New Orleans, LA 70123. (c) States of California, Oregon, Washington,

Hawaii, or U.S. territories in the Pacific

Ocean. Regional Supervisor for Resource Evaluation, Bureau of Ocean Energy Management, Pacific OCS Region, 770 Paseo Camarillo, Camarillo, CA 93010.

**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 endangeroperations 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.

**§ 580.21 What must I do in conducting G&G prospecting or scientific research?** 

While conducting G&G prospecting or
scientific research activities under a permit or notice, you must:

(a) Immediately report to the Regional Director if you:

(1) Detect hydrocarbon or any other mineral occurrences;

(2) Detect environmental hazards that imminently threaten life and property;

or (3) Adversely affect the environment, aquatic life, archaeological resources, or other uses of the area where you are prospecting or conducting scientific
research activities. (b) Consult and coordinate your G&G
activities with other users of the area for navigation and safety purposes.

(c) If you conduct shallow test drilling or deep stratigraphic test drilling activities, you must use the best available and safest technologies that the Regional Director considers economically feasible.

**§ 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. (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 When may BOEM cancel my permit?** 

The Regional Director may cancel a permit at any time.

(a) If we cancel your permit, the Regional Director will advise you by certified or registered mail 30 days
before the cancellation date and will
state the reason.

(b) After we cancel your permit, you are still responsible for proper abandonment of any drill site according to the requirements of 30 CFR 251.7(b)(8). You must comply with all other obligations specified in this part or in the permit.

**§ 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.

**§ 580.30 What activities will not require environmental analysis?** 

We anticipate that activities of the type listed below typically will not cause significant environmental impact and will normally be categorically
excluded from additional environmental analysis. The types of activities include:

(a) Gravity and magnetometric observations and measurements;

(b) Bottom and subbottom acoustic profiling or imaging without the use of explosives; (c) Hard minerals sampling of a
limited nature such as shallow test drilling;

(d) Water and biotic sampling, if the sampling does not adversely affect shellfish beds, marine mammals, or an endangered species or if permitted by
the National Marine Fisheries Service or another Federal agency;

(e) Meteorological observations and measurements, including the setting of
instruments;

(f) Hydrographic and oceanographic observations and measurements, including the setting of instruments;

(g) Sampling by box core or grab sampler to determine seabed geological or geotechnical properties;

(h) Television and still photographic observation and measurements;

(i) Shipboard hard mineral assaying and analysis; and

(j) Placement of positioning systems, including bottom transponders and surface and subsurface buoys reported

in Notices to Mariners.

**§ 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 What penalties may I be subject**

**to?**

(a) Penalties for noncompliance under a permit. You are subject to the penalty provisions of section 24 of the Act (43 U.S.C. 1350) and the procedures contained in 30 CFR part 550, subpart N for noncompliance with:

(1) Any provision of the Act; (2) Any provisions of a G&G or drilling permit; or

(3) Any regulation or order issued
under the Act.

(b) Penalties under other laws and regulations. The penalties prescribed in this section are in addition to any other penalty imposed by any other law or regulation.

**§ 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

**§ 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 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.

**§ 580.51 What types of geophysical data**
**and information must I submit to BOEM?**

Unless the Regional Director specifies otherwise, you must include:

(a) An accurate and complete record of each geophysical survey conducted under the permit, including digital navigational data and final location

maps;

(b) All seismic data collected under a permit presented in a format and of a quality suitable for processing;

(c) Processed geophysical information
derived from seismic data with extraneous signals and interference removed, presented in a quality format suitable for interpretive evaluation, reflecting state-of-the-art processing techniques; and

(d) Other geophysical data, processed geophysical information, and interpreted geophysical information including, but not limited to, shallow and deep subbottom profiles, bathymetry, sidescan sonar, gravity and magnetic surveys, and special studies such as refraction and velocity surveys.

**§ 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 (b) A permittee or third party that sells, trades, licenses, or otherwise provides data and information to a third party must advise the recipient, in writing, that accepting these obligations is a condition precedent of the sale, trade, license, or other agreement; and

(c) Except for license agreements, a permittee or third party that sells, trades, or otherwise provides data and information to a third party must advise the Regional Director, in writing within 30 days of the sale, trade, or other agreements, including the identity of the recipient of the data and information; or

(d) For license agreements, a permittee or third party that licenses data and information to a third party must, within 30 days of a request by the Regional Director, advise the Regional Director, in writing, of the license agreement, including the identity of the recipient of the data and information.

Reimbursement

**§ 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) Geological data and information, 10 years after issuing the permit. (2) Geophysical data, 50 years after you or a third party submit the data. (3) Geophysical information, 25 years after you or a third party submit the information. (4) Data and information related to a deep stratigraphic test, 25 years after you complete the test, unless the provisions of p aragraph (b) of this section apply.

(b) This paragraph applies if you are covered by paragraph (a)(4) of this
section and a lease sale is held or a noncompetitive agreement is negotiated after you complete a test well. We will
release the data and information related to the deep stratigraphic test at the earlier of the following times:

(1) Twenty-five years after you complete the test; or

(2) Sixty calendar days after we issue a lease, located partly or totally within 50 geographic miles (92.7 kilometers) of
the test.

**§ 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. **§ 580.73 Will BOEM share data and**

**information with coastal States?**

(a) We can disclose proprietary data, information, and samples submitted to us by permittees or third parties that we receive under this part to the Governor of any adjacent State that requests it according to paragraphs (b), (c), and (d) of this section. The permittee or third parties who submitted proprietary data, information, and samples will be
notified about the disclosure and will have at least five working days to
comment on the action.

(b) We will make a disclosure under this section only after the Governor and the Secretary have entered into an agreement containing all of the following provisions:

(1) The confidentiality of the
information will be maintained.

(2) In any action taken for failure to protect the confidentiality of proprietary information, neither the Federal Government nor the State may raise as
a defense:

(i) Any claim of sovereign immunity;

or (ii) Any claim that the employee who revealed the proprietary information was acting outside the scope of his/her employment in revealing the
information.

(3) The State agrees to hold the Federal Government harmless for any violation by the State or its employees or contractors of the agreement to protect the confidentiality of proprietary data and information and samples.

(4) The materials containing the proprietary data, information, and samples will remain the property of the
Federal Government.

(c) The data, information, and samples available for reproduction to the State(s) under an agreement must be
related to leased lands. Data and information on unleased lands may be viewed but not copied or reproduced.

(d) The State must return to us the materials containing the proprietary data, information, and samples when we ask for them or when the State no longer
needs them.

(e) Information received and knowledge gained by a State official under paragraph (d) of this section is subject to confidentiality requirements
of:

(1) The Act; and (2) The regulations at 30 CFR parts 580, 581, and 582.

**Subpart E—Information Collection**

**§ 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**

**Subpart A—General**

Sec. 581.0 Authority for information collection. 581.1 Purpose and applicability. 581.2 Authority.

581.3 Definitions. 581.4 Qualifications of lessees.

581.5 False statements. 581.6 Appeals.

581.7 Disclosure of information to the public. 581.8 Rights to minerals. 581.9 Jurisdictional controversies.

**Subpart B—Leasing Procedures**

581.11 Unsolicited request for a lease sale. 581.12 Request for OCS mineral

information and interest. 581.13 Joint State/Federal coordination. 581.14 OCS mining area identification.

581.15 Tract size. 581.16 Proposed leasing notice. 581.17 Leasing notice. 581.18 Bidding system.

581.19 Lease term.
581.20 Submission of bids.

581.21 Award of leases.

581.22 Lease form.

581.23 Effective date of leases.

**Subpart C—Financial Considerations**

581.26 Payments.
581.27 Annual rental. 581.28 Royalty. 581.29 Royalty valuation. 581.30 Minimum royalty. 581.31 Overriding royalties. 581.32 Waiver, suspension, or reduction of rental, minimum royalty, or production royalty. 581.33 Bonds and bonding requirements.

**Subpart D—Assignments and Lease**

**Extensions**

581.40 Assignment of leases or interests

therein. 581.41 Requirements for filing for transfers. 581.42 Effect of assignment on particular

lease. 581.43 Effect of suspensions on lease term.

**Subpart E—Termination of Leases**

581.46 Relinquishment of leases or parts of

leases.

581.47 Cancellation of leases.

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

**Subpart A—General**

**§ 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)). **§ 581.3 Definitions.** When used in this part, the following terms shall have the following meaning:

Act means the OCS Lands Act, as amended (43 U.S.C. 1331 et seq. ).

Adjacent State means with respect to any activity proposed, conducted, or approved under this part, any coastal

State—

(1) That is, or is proposed to be, receiving for processing, refining, or transshipping OCS mineral resources commercially recovered from the seabed;

(2) That is used, or is scheduled to be used, as a support base for prospecting, exploration, testing, and mining
activities; or

(3) In which there is a reasonable probability of significant effect on land or water uses from such activity.

Director means the Director of the Bureau of Ocean Energy Management (BOEM) of the U.S. Department of the
Interior or an official authorized to act
on the Director’s behalf.

Governor means the Governor of a State or the person or entity designated by, or pursuant to, State law to exercise the powers granted to such Governor pursuant to the Act.

Lease means any form of
authorization which is issued under
section 8 of the Act and which authorizes exploration for, and development and production of, minerals, or the area covered by that authorization, whichever is required by
the context.

Lessee means the person authorized by a lease, or an approved assignment thereof, to explore for and develop and produce the leased deposits in accordance with the regulations in this chapter. The term includes all persons holding that authority by or through the
lessee.

OCS mineral means a mineral deposit
or accretion found on or below the
surface of the seabed but does not include oil, gas, sulphur; salt or sand and gravel intended for use in association with the development of oil, gas, or sulphur; or source materials essential to production of fissionable
materials which are reserved to the United States pursuant to section 12(e)
of the Act.

Outer Continental Shelf means all submerged lands lying seaward and
outside of the area of lands beneath navigable waters as defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of which the subsoil and seabed appertain to the United States and are subject to its jurisdiction and
control.

Overriding royalty means a royalty
created out of the lessee’s interest which


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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.

**§ 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 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. **Subpart B—Leasing Procedures**

**§ 581.11 Unsolicited request for a lease**

**sale.**

(a) Any person may at any time request that OCS minerals be offered for lease. A request that OCS minerals be
offered for lease shall be submitted to
the Director and shall contain the following information:

(1) The area to be offered for lease. (2) The OCS minerals of primary

interest.

(3) The available OCS mineral
resource and environmental information pertaining to the area of interest to be offered for lease which supports the
request.

(b) Within 45 days after receipt of a request submitted under paragraph (a) of this section, the Director shall either initiate steps leading to the offer of OCS minerals for lease and notify the applicant of the action taken or inform the applicant of the reasons for not initiating steps leading to the offer of
OCS minerals for lease.

(c) Any interested party may at any
time submit information to the Director concerning the scheduling of proposed lease sales of OCS minerals in any area of the OCS. Such information may include but not be limited to any of the following:

(1) Benefits of conducting a lease sale

in an area.

(2) Costs of conducting a lease sale in

an area.

(3) Geohazards which could be
encountered in an area.

(4) Geological information about an area and mineral resource potential.

(5) Environmental information about

an area.

(6) Information about known archaeological resources in an area.

**§ 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.

**§ 581.13 Joint State/Federal coordination.**

(a) The Secretary may invite the adjacent State Governor(s) to join in, or the adjacent State Governor(s) may request that the Secretary join in, the
establishment of a State/Federal task force or some other joint planning or coordination arrangement when industry interest exists for OCS mineral leasing or geological information appears to support the leasing of OCS minerals in specific areas. Participation in joint State/Federal task forces or other arrangements will afford the adjacent State Governor(s) opportunity
for access to available data and information about the area; knowledge of progress made in the leasing process and of the results of subsequent exploration and development activities;
facilitate the resolution of issues of mutual interest; and provide a mechanism for planning, coordination, consultation, and other activities which the Secretary and the Governor(s) may identify as contributing to the leasing

process.

(b) State/Federal task forces or other such arrangements are to be constituted pursuant to such terms and conditions (consistent with Federal law and these regulations) as the Secretary and the adjacent State Governor(s) may agree.

(c) State/Federal task forces or other such arrangements will provide a forum which the Secretary and adjacent State Governor(s) may use for planning, consultation, and coordination on concerns associated with the offering of OCS minerals other than oil, gas, or sulphur for lease.

(d) With respect to the activities authorized under these regulations each State/Federal task force may make recommendations to the Secretary and adjacent State Governor(s) concerning: (1) The identification of areas in which OCS minerals might be offered for lease;

(2) The potential for conflicts between the exploration and development of OCS mineral resources, other users and uses of the area, and means for resolution or mitigation of these conflicts;

(3) The economic feasibility of developing OCS mineral resources in the area proposed for leasing;

(4) Potential environmental problems and measures that might be taken to mitigate these problems;

(5) Development of guidelines and procedures for safe, environmentally responsible exploration and development practices; and

(6) Other issues of concern to the Secretary and adjacent State Governor(s).

(e) State/Federal task forces or other such arrangements might also be used to conduct or oversee research, studies, or reports ( e.g., Environmental Impact Statements).

**§ 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 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,


### 64714 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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.

**§ 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. **§ 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 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**

**§ 581.26 Payments.**

(a) For sealed bids, a bonus bid deposit of a specified percentage of the total amount bid is required to be submitted with the bid. The percentage of bonus bid required to be deposited will be specified in the leasing notice. The remittance may be made in cash or by Federal Reserve check, commercial check, bank draft, money order, certified check, or cashier’s check made payable to ‘‘Department of the Interior—BOEM.’’ Payment of this portion of the bonus bid may not be made by Electronic Funds
Transfer.

(b) For oral bids, a bonus bid deposit of a specified percentage of the total
amount bid must be submitted to the official designated in the leasing notice following the completion of the oral bidding. The percentage of bonus bid required to be deposited will be specified in the leasing notice. Payment of this portion of the bonus bid must be made by Electronic Fund Transfer within the timeframe specified in the leasing notice.

(c) The deposit received from high bidders will be placed in a Treasury account pending acceptance or rejection
of the bid. Other bids submitted under paragraph (a) of this section will be returned to the bidders. If the high bid is subsequently rejected, an amount equal to that deposited with the high bid will be returned according to applicable regulations.

(d) The balance of the winning bonus bid and all rentals and royalties must be paid in accordance with the terms and conditions of this part, the Leasing Notice, and Subchapter A of this chapter.

(e) For each lease issued pursuant to this subpart, there shall be one person identified who shall be solely responsible for all payments due and payable under the provisions of the lease. The single responsible person shall be designated as the payor for the
lease and shall be so identified on the Solid Minerals Production and Royalty Report (P&R) (Form ONRR–4430) in
accordance with 30 CFR 1210.201 of this title. The designated person shall be responsible for all bonus, rental, and royalty payments.

(f) Royalty shall be computed at the rate specified in the leasing notice, and paid in value unless the Secretary elects to have the royalty delivered in kind.

(g) For leases which provide for minimum royalty payments, each lessee shall pay the minimum royalty specified in the lease at the end of each lease year beginning with the lease year in which production royalty is paid (whether the full amount specified in the lease or 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. (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.

**§ 581.32 Waiver, suspension, or reduction of rental, minimum royalty, or production**  **royalty.**

(a) The Secretary may waive, suspend, or reduce the rental, minimum royalty, and/or production royalty prescribed in a lease for a specified time period when the Secretary determines that it is in the National interest, it will result in the
conservation of natural resources of the OCS, it will promote development, or the mine cannot be successfully operated under existing conditions.

(b) An application for waiver, suspension, or reduction of rental, minimum royalty, or production royalty under paragraph (a) of this section shall be filed in duplicate with the Director. The application shall contain the serial number(s) of the lease(s), the name of the lessee(s) of record, and the operator(s) if applicable. The application shall either:

(1)(i) Show the location and extent of all mining operations and a tabulated
statement of the minerals mined and subject to royalty for each of the last 12 months immediately prior to filing the application:

(ii) Contain a detailed statement of expenses and costs of operating the lease, the income from the sale of any lease products, and the amount of all overriding royalties and payments out of production paid to others than the United States; and

(iii) All facts showing whether or not the mine(s) can be successfully operated under the royalty fixed in the lease; or

(2) If no production has occurred from the lease, show that the lease cannot be successfully operated under the rental, royalty, and other conditions specified
in the lease.

(c) The applicant for a waiver, suspension, or reduction under this
section shall file documentation that the lessee and the royalty holders agree to a reduction of all other royalties from the lease so that the aggregate of all other royalties does not exceed one-half the amount of the reduced royalties that would be paid to the United States.

**§ 581.33 Bonds and bonding requirements.** 

(a) When the leasing notice specifies that payment of a portion of the bonus bid can be deferred, the lessee shall be required to submit a surety or personal bond to guarantee payment of a deferred portion of the bid. Upon the payment of the full amount of the cash bonus bid,
the lessee’s bond will be released.

(b) All bonds to guarantee payment of the deferred portion of the high cash bonus bid furnished by the lessee must be in a form or on a form approved by
the Associate Director for BOEM. A single copy of the required form is to be executed by the principal or, in the case of surety bonds, by both the principal and an acceptable surety.

(1) Only those surety bonds issued by qualified surety companies approved by the Department of the Treasury shall be accepted (see Department of the Treasury Circular No. 570 and any supplemental or replacement circulars).

(2) Personal bonds shall be accompanied by a cashier’s check, certified check, or negotiable U.S. Treasury bonds of an equal value to the amount specified in the bond. Negotiable Treasury bonds shall be accompanied by a proper conveyance of full authority to the Director to sell such
securities in case of default in the performance of the terms and conditions
of the lease.

(c) Prior to the commencement of any activity on a lease(s), the lessee shall submit a surety or personal bond as described in § 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 Assignment of leases or interests**

**therein.**

(a) Subject to the approval of the Secretary, a lease may be assigned, in whole or in part, pursuant to section 8(e) of the Act to anyone qualified to
hold a lease.

(b) Any approved assignment shall be deemed to be effective on the first day of the lease month following the date
that it is submitted to the Director for approval unless by written request the parties request that the effective date be
the first of the month in which the Director approves the assignment.

(c) The assignor shall be liable for all obligations under the lease occurring prior to the effective date of an assignment.

(d) The assignee shall be liable for all obligations under the lease occurring on
or after the effective date of an assignment and shall comply with all
terms and conditions of the lease and applicable regulations issued under the

Act.

**§ 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


### 64717 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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.

**§ 581.42 Effect of assignment on particular**

**lease.**

(a) When an assignment is made of all the record title to a portion of the acreage in a lease, the assigned and retained portions of the lease area become segregated into separate and distinct leases. In such a case, the assignee becomes a lessee of the Government as to the segregated tract that is the subject of the assignment and is bound by the terms of the lease as though the lease had been obtained from the United States in the assignee’s own name, and the assignment, after its approval, shall be the basis of a new record. Royalty, minimum royalty, and annual rental provisions of the lease shall apply separately to each segregated portion.

(b) Each lease of an OCS mineral created by the segregation of a lease under paragraph (a) of this section shall
continue in full force and effect for the remainder of the primary term of the original lease and so long thereafter as minerals are produced from the portion of the lease created by segregation in accordance with operations approved by
the Director or the lessee is otherwise in compliance with provisions of the lease or regulations for earning the
continuation of the lease in effect.

**§ 581.43 Effect of suspensions on lease**

**term.**

(a) If the BSEE Director orders the suspension of either operations or production, or both, with respect to any lease in its primary term, the primary term of the lease shall be extended by a period of time equivalent to the period of the directed suspension.

(b) If the BSEE Director orders or approves the suspension of either operations or production, or both, with respect to any lease that is in force beyond its primary term, the term of the lease shall not be deemed to expire so long as the suspension remains in effect.

**Subpart E—Termination of Leases**

**§ 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 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**

**Subpart A—General**

Sec. 582.0 Authority for information collection. 582.1 Purpose and authority. 582.2 Scope.

582.3 Definitions. 582.4 Opportunities for review and

comment.
582.5 Disclosure of data and information to the public.

582.6 Disclosure of data and information to an adjacent State. 582.7 Jurisdictional controversies.

**Subpart B—Jurisdiction and Responsibilities of Director** 

582.10 Jurisdiction and responsibilities of

Director. 582.11 Director’s authority. 582.12 Director’s responsibilities. 582.13 [Reserved] 582.14 Noncompliance, remedies, and penalties.

582.15 Cancellation of leases. **Subpart C—Obligations and Responsibilities of Lessees** 

582.20 Obligations and responsibilities of

lessees. 582.21 Plans, general.

582.22 Delineation Plan. 582.23 Testing Plan. 582.24 Mining Plan.

582.25 Plan modification. 582.26 Contingency Plan. 582.27 Conduct of operations. 582.28 Environmental protection measures. 582.29 Reports and records. 582.30 Right of use and easement. 582.31 [Reserved]

**Subpart D—Payments**

582.40 Bonds. 582.41 Method of royalty calculation. 582.42 Payments.

**Subpart E—Appeals**

582.50 Appeals.

Authority: 43 U.S.C. 1334.

**Subpart A—General**

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

**§ 582.3 Definitions.**

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

Act means the OCS Lands Act, as amended (43 U.S.C. 1331 et seq. ).

Adjacent State means with respect to any activity proposed, conducted, or approved under this part, any coastal

State:

(1) That is, or is proposed to be, receiving for processing, refining, or transshipment OCS mineral resources commercially recovered from the seabed;

(2) That is used, or is scheduled to be used, as a support base for prospecting, exploration, testing, or mining activities;

or (3) In which there is a reasonable probability of significant effect on land or water uses from such activity.

Contingency Plan means a plan for action to be taken in emergency

situations.

Data means geological and geophysical (G&G) facts and statistics or samples which have not been analyzed, processed, or interpreted.

Development means those activities which take place following the discovery of minerals in paying quantities including geophysical activities, drilling, construction of offshore facilities, and operation of all onshore support facilities, which are for the purpose of ultimately producing the
minerals discovered.

Director means the Director of BOEM of the U.S. Department of the Interior or
an official authorized to act on the
Director’s behalf.

Exploration means the process of searching for minerals on a lease including:

(1) Geophysical surveys where magnetic, gravity, seismic, or other systems are used to detect or imply the presence of minerals;

(2) Any drilling including the drilling of a borehole in which the discovery of a mineral other than oil, gas, or sulphur is made and the drilling of any
additional boreholes needed to delineate any mineral deposits; and

(3) The taking of sample portions of a mineral deposit to enable the lessee to determine whether to proceed with development and production.

Geological sample means a collected portion of the seabed, the subseabed, or


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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 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 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).

**§ 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. **§ 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 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.

**§ 582.12 Director’s responsibilities.**

(a) The Director is responsible for the regulation of activities to assure that all operations conducted under a lease or right of use and easement are conducted in a manner that protects the environment and promotes orderly development of OCS mineral resources. Those activities are to be designed to prevent serious harm or damage to, or waste of, any natural resource (including OCS mineral deposits and oil, gas, and sulphur resources in areas leased or not leased), any life (including fish and other aquatic life), property, or the marine, coastal, or human

environment.

(b)(1) In the evaluation of a Delineation Plan, the Director shall consider whether the plan is consistent
with:

(i) The provisions of the lease; (ii) The provisions of the Act; (iii) The provisions of the regulations prescribed under the Act;

(iv) Other applicable Federal law; and (v) Requirements for the protection of the environment, health, and safety.

(2) Within 30 days following the completion of an environmental
assessment or other NEPA document prepared pursuant to the regulations implementing NEPA or within 30 days following the comment period provided in § 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 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]**

**§ 582.14 Noncompliance, remedies, and penalties.** 

(a)(1) If the Director determines that a lessee has failed to comply with applicable provisions of law; the regulations in this part; other applicable regulations; the lease; the approved Delineation, Testing, or Mining Plan; or the Director’s orders or instructions, and
the Director determines that such noncompliance poses a threat of immediate, serious, or irreparable damage to the environment, the mine or the deposit being mined, or other valuable mineral deposits or other resources, the Director shall order the
lessee to take immediate and appropriate remedial action to alleviate the threat. Any oral orders shall be followed up by service of a notice of noncompliance upon the lessee by delivery in person to the lessee or agent, or by certified or registered mail
addressed to the lessee at the last known
address.

(2) If the Director determines that the lessee has failed to comply with applicable provisions of law; the regulations in this part; other applicable regulations; the lease; the requirements of an approved Delineation, Testing, or Mining Plan; or the Director’s orders or instructions, and such noncompliance does not pose a threat of immediate, serious, or irreparable damage to the environment, the mine or the deposit being mined, or other valuable mineral deposits or other resources, the Director shall serve a notice of noncompliance upon the lessee by delivery in person to the lessee or agent or by certified or registered mail addressed to the lessee
at the last known address.

(b) A notice of noncompliance shall specify in what respect(s) the lessee has failed to comply with the provisions of applicable law; regulations; the lease; the requirements of an approved Delineation, Testing, or Mining Plan; or the Director’s orders or instructions, and shall specify the action(s) which must be taken to correct the noncompliance
and the time limits within which such
action must be taken.

(c) Failure of a lessee to take the actions specified in the notice of noncompliance within the time limit specified shall be grounds for a suspension of operations and other appropriate actions, including but not
limited to the assessment of a civil penalty of up to $10,000 per day for
each violation that is not corrected within the time period specified (43 U.S.C. 1350(b)).

(d) Whenever the Director determines that a violation of or failure to comply with any provision of the Act; or any provision of a lease, license, or permit issued pursuant to the Act; or any provision of any regulation promulgated under the Act probably occurred and that such apparent violation continued beyond notice of the violation and the expiration of the reasonable time period allowed for corrective action, the Director shall follow the procedures concerning remedies and penalties in subpart N, Remedies and Penalties, of 30 CFR part 550 to determine and assess an appropriate penalty.

(e) The remedies and penalties prescribed in this section shall be concurrent and cumulative, and the exercise of one shall not preclude the exercise of the other. Further, the remedies and penalties prescribed in this section shall be in addition to any other remedies and penalties afforded by any other law or regulation (43 U.S.C. 1350(e)).

**§ 582.15 Cancellation of leases.**

(a) Whenever the owner of a nonproducing lease fails to comply with any of the provisions of the Act, the lease, or the regulations issued under the Act, and the default continues for a period of 30 days after mailing of notice by registered or certified letter to the lease owner at the owner’s record post office address, the Secretary may cancel the lease pursuant to section 5(c) of the Act, and the lessee shall not be entitled to compensation. Any such cancellation is subject to judicial review as provided by section 23(b) of the Act.

(b) Whenever the owner of any producing lease fails to comply with any of the provisions of the Act, the lease, or the regulations issued under the Act, the Secretary may cancel the lease only after judicial proceedings pursuant to section 5(d) of the Act, and
the lessee shall not be entitled to compensation.

(c) Any lease issued under the Act, whether producing or not, may be canceled by the Secretary upon proof that it was obtained by fraud or misrepresentation and after notice and opportunity to be heard has been
afforded to the lessee.

(d) The Secretary may cancel a lease in accordance with the following:

(1) Cancellation may occur at any time if the Secretary determines after a hearing that:

(i) Continued activity pursuant to such lease would probably cause serious harm or damage to life (including fish and other aquatic life), to property, to any mineral (in areas leased or not leased), to the National security or defense, or to the marine, coastal, or human environment;

(ii) The threat of harm or damage will not disappear or decrease to an acceptable extent within a reasonable period of time; and

(iii) The advantages of cancellation outweigh the advantages of continuing
such lease in force.

(2) Cancellation shall not occur unless and until operations under such lease shall have been under suspension or temporary prohibition by the Secretary, with due extension of any lease term continuously for a period of 5 years or for a lesser period upon request of the lessee;

(3) Cancellation shall entitle the lessee to receive such compensation as is shown to the Secretary as being equal
to the lesser of:

(i) The fair value of the canceled rights as of the date of cancellation, taking account of both anticipated revenues from the lease and anticipated costs, including costs of compliance with all applicable regulations and operating orders, liability for cleanup costs or damages, or both, and all other costs reasonably anticipated on the lease, or

(ii) The excess, if any, over the lessee’s revenue from the lease (plus interest thereon from the date of receipt to date of reimbursement) of all consideration paid for the lease and all direct expenditures made by the lessee
after the date of issuance of such lease and in connection with exploration or development, or both, pursuant to the lease (plus interest on such consideration and such expenditures from date of payment to date of reimbursement), except that in the case


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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** 

**§ 582.20 Obligations and responsibilities**

**of lessees.**

(a) The lessee shall comply with the provisions of applicable laws; regulations; the lease; the requirements of the approved Delineation, Testing, or Mining Plans; and other written or oral orders or instructions issued by the Director when performing exploration, testing, development, and production activities pursuant to a lease issued under 30 CFR part 581. The lessee shall take all necessary precautions to prevent waste and damage to oil, gas, sulphur, and other OCS mineral-bearing formations and shall conduct operations
in such manner that does not cause or threaten to cause harm or damage to life (including fish and other aquatic life); to property; to the National security or defense; or to the marine, coastal, or human environment (including onshore air quality). The lessee shall make all
mineral resource data and information
and all environmental data and information acquired by the lessee in the course of exploration, testing, development, and production operations on the lease available to the Director for examination and copying at
the lease site or an onshore location
convenient to the Director.

(b) In all cases where there is more than one lease owner of record, one person shall be designated payor for the lease. The payor shall be responsible for making all rental, minimum royalty, and royalty payments.

(c) In all cases where lease operations are not conducted by the sole lessee, a ‘‘designation of operator’’ shall be submitted to and accepted by the Director prior to the commencement of leasehold operations. This designation when accepted will be recognized as authority for the designee to act on
behalf of the lessees and to fulfill the lessees’ obligations under the Act, the lease, and the regulations of this part. All changes of address and any termination of a designation of operator shall be reported immediately, in writing, to the Director. In the case of a termination of a designation of operator or in the event of a controversy between the lessee and the designated operator, both the lessee and the designated operator will be responsible for the protection of the interests of the lessor.

(d) When required by the Director or at the option of the lessee, the lessee
shall submit to the Director the designation of a local representative empowered to receive notices, provide
access to OCS mineral and environmental data and information, and comply with orders issued pursuant to the regulations of this part. If there is a change in the designated representative, the Director shall be notified immediately.

(e) Before beginning operations, the
lessee shall inform the Director in writing of any designation of a local representative under paragraph (d) of
this section and the address of the mine office responsible for the exploration, testing, development, or production activities; the lessee’s temporary and permanent addresses; or the name and address of the designated operator who will be responsible for the operations,
and who will act as the local representative of the lessee. The
Director shall also be informed of each change thereafter in the address of the
mine office or in the name or address of the local representative.

(f) The holder of a right-of-use and easement shall exercise its rights under the right of use and easement in accordance with the regulations of this
part.

(g) A lessee shall submit reports and
maintain records in accordance with § 582.29 of this part.

(h) When an oral approval is given by BOEM in response to an oral request under these regulations, the oral request shall be confirmed in writing by the lessee or holder of a right of use and
easement within 72 hours.

(i) The lessee is responsible for obtaining all permits and approvals from BOEM, BSEE or other Agencies needed to carry out exploration, testing, development, and production activities under a lease issued under 30 CFR part
581 of this title.

**§ 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.

**§ 582.22 Delineation Plan.**

All exploration activities shall be
conducted in accordance with a Delineation Plan submitted by the lessee and approved by the Director. The
Delineation Plan shall describe the proposed activities necessary to locate leased OCS minerals, characterize the quantity and quality of the minerals, and generate other information needed for the development of a comprehensive Testing or Mining Plan. A Delineation
Plan at a minimum shall include the following:

(a) The OCS mineral(s) or primary

interest.

(b) A brief narrative description of the
activities to be conducted and how the activities will lead to the discovery and evaluation of a commercially minable deposit on the lease.

(c) The name, registration, and type of equipment to be used, including vessel types as well as their navigation and mobile communication systems, and transportation corridors to be used
between the lease and shore.

(d) Information showing that the equipment to be used (including the vessel) is capable of performing the intended operation in the environment
which will be encountered.

(e) Maps showing the proposed locations of test drill holes, the anticipated depth of penetration of test drill holes, the locations where surficial samples were taken, and the location of proposed geophysical survey lines for each surveying method being employed. (f) A description of measures to be taken to avoid, minimize, or otherwise mitigate air, land, and water pollution and damage to aquatic and wildlife species and their habitats; any unique or special features in the lease area; aquifers; other natural resources of the OCS; and hazards to public health, safety, and navigation.

(g) A schedule indicating the starting and completion dates for each proposed exploration activity.

(h) A list of any known archaeological
resources on the lease and measures to assure that the proposed exploration activities do not damage those

resources.

(i) A description of any potential
conflicts with other uses and users of
the area.

(j) A description of measures to be
taken to monitor the effects of the proposed exploration activities on the
environment in accordance with § 582.28(c) of this part.

(k) A detailed description of practices and procedures to effect the abandonment of exploration activities,

e.g., plugging of test drill holes. The proposed procedures shall indicate the steps to be taken to assure that test drill holes and other testing procedures which penetrate the seafloor to a significant depth are properly sealed
and that the seafloor is left free of obstructions or structures that may present a hazard to other uses or users of the OCS such as navigation or commercial fishing.

(l) A detailed description of the cycle of all materials, the method for discharge and disposal of waste and refuse, and the chemical and physical
characteristics of waste and refuse.

(m) A description of the potential environmental impacts of the proposed exploration activities including the following:

(1) The location of associated port, transport, processing, and waste disposal facilities and affected environment ( e.g., maps, land use, and layout);

(2) A description of the nature and degree of environmental impacts and
the domestic socioeconomic effects of construction and operation of the associated facilities, including waste characteristics and toxicity;

(3) Any proposed mitigation measures to avoid or minimize adverse impacts on the environment;

(4) A certificate of consistency with the federally approved State coastal zone management program, where applicable; and

(5) Alternative sites and technologies considered by the lessee and the reasons why they were not chosen. (n) Any other information needed for technical evaluation of the planned activity, such as sample analyses to be conducted at sea, and the evaluation of potential environmental impacts.

**§ 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


### 64725 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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.

**§ 582.24 Mining Plan.**

All OCS mineral development and production activities shall be conducted in accordance with a Mining Plan submitted by the lessee and approved by the Director. A Mining Plan shall include comprehensive detailed descriptions, illustrations, and explanations of the proposed OCS mineral development, production, and processing activities and accurately present the lessee’s proposed plan of operation. A Mining Plan at a minimum shall include the following:

(a) A narrative description of the mining activities including:

(1) The OCS mineral(s) or material(s) to be recovered;

(2) Estimates of the number of tons and grade(s) of ore to be recovered;

(3) Anticipated annual production; (4) Volume of ocean bottom expected to be disturbed (area and depth of disruption) each year; and

(5) All activities of the mining cycle from extraction through processing and waste disposal.

(b) Maps of the lease showing water depths, the outline of the mineral deposit(s) to be mined with cross sections showing thickness, and the area(s) anticipated to be mined each

year.

(c) The name, registration, and type of equipment to be used, including vessel types as well as their navigation and mobile communication systems, and transportation corridors to be used
between the lease and shore.

(d) Information showing that the equipment to be used (including the vessel) is capable of performing the intended operation in the environment
which will be encountered.

(e) A description of equipment to be used in mining, processing, and transporting of the ore.

(f) A schedule indicating the anticipated starting and completion dates for each activity described in the plan.

(g) For onshore processing, a description of how OCS minerals are to be processed and how the produced OCS minerals will be weighed, assayed, and royalty determinations made.

(h) For at-sea processing, additional information including type and size of
installation or structures and the method of tailings disposal.

(i) A list of known archaeological
resources on the lease and the measures to be taken to assure that the proposed mining activities do not damage those

resources.

(j) Description of any potential
conflicts with other uses and users of
the area.

(k) A detailed description of the
nature and occurrence of the OCS mineral deposit(s) in the leased area with adequate maps and sections.

(l) A detailed description of development and mining methods to be used, the proposed sequence of mining or development, the expected production rate, the method and location of the proposed processing operation, and the method of measuring production. (m) A detailed description of the method of transporting the produced
OCS minerals from the lease to shore and adequate maps showing the locations of pipelines, conveyors, and other transportation facilities and
corridors.

(n) A detailed description of the cycle of all materials including samples and wastes, the method of discharge and disposal of waste and refuse, and the chemical and physical characteristics of
the waste and refuse.

(o) A description of measures to be taken to avoid, minimize, or otherwise mitigate air, land, and water pollution and damage to aquatic and wildlife species and their habitats; any unique or special features in the lease area, aquifers, or other natural resources of the OCS; and hazards to public health, safety, and navigation.

(p) A detailed description of measures to be taken to monitor the impacts of the proposed mining and processing
activities on the environment in accordance with § 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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**§ 582.25 Plan modification.**

Approved Delineation, Testing, and Mining Plans may be modified upon the Director’s approval of the changes proposed. When circumstances warrant, the Director may direct the lessee to modify an approved plan to adjust to changed conditions. If the lessee requests the change, the lessee shall submit a detailed, written statement of the proposed modifications, potential impacts, and the justification for the proposed changes. Revision of an approved plan whether initiated by the lessee or ordered by the Director shall
be submitted to the Director for approval. When the Director determines that a proposed revision could result in significant change in the impacts previously identified and evaluated or requires additional permits, the proposed plan revision shall be subject to the applicable review and approval procedures of §§ 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]

**§ 582.28 Environmental protection**

**measures.**

(a) Exploration, testing, development, production, and processing activities proposed to be conducted under a lease will only be approved by the Director upon the determination that the adverse impacts of the proposed activities can be avoided, minimized, or otherwise mitigated. The Director shall take into
account the information contained in the sale-specific environmental evaluation prepared in association with the lease offering as well as the site- and operational-specific environmental evaluations prepared in association with
the review and evaluation of the approved Delineation, Testing, or Mining Plan. The Director’s review of the air quality consequences of proposed OCS activities will follow the practices and procedures specified in 30 CFR 250.194, §§ 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 andmitigating 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 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;


### 64727 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

(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 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. **§ 582.31 [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


### 64728 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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.

**§ 582.41 Method of royalty calculation.**

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

**§ 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.

**PART 585—RENEWABLE ENERGY**
**AND ALTERNATE USES OF EXISTING**
**FACILITIES ON THE OUTER**
**CONTINENTAL SHELF**

**Subpart A—General Provisions**

Sec. 585.100 Authority. 585.101 What is the purpose of this part? 585.102 What are BOEM’s responsibilities under this part? 585.103 When may BOEM prescribe or approve departures from these regulations?

585.104 Do I need a BOEM lease or other authorization to produce or support the production of electricity or other energy product from a renewable energy

resource on the OCS? 585.105 What are my responsibilities under this part? 585.106 Who can hold a lease or grant under this part? 585.107 How do I show that I am qualified to be a lessee or grant holder? 585.108 When must I notify BOEM if an action has been filed alleging that I am insolvent or bankrupt? 585.109 When must I notify BOEM of mergers, name changes, or changes of
business form? 585.110 How do I submit plans, applications, reports, or notices required by this part? 585.111 When and how does BOEM charge me processing fees on a case-by-case
basis?
585.112 Definitions.
585.113 How will data and information obtained by BOEM under this part be disclosed to the public? 585.114 Paperwork Reduction Act
statements—information collection. 585.115 Documents incorporated by
reference. 585.116 Requests for information on the state of the offshore renewable energy industry. 585.117 [Reserved] 585.118 What are my appeal rights?

**Subpart B—Issuance of OCS Renewable Energy Leases** 

General Lease Information

585.200 What rights are granted with a lease issued under this part?
585.201 How will BOEM issue leases? 585.202 What types of leases will BOEM

issue?
585.203 With whom will BOEM consult
before issuance of a lease? 585.204 What areas are available for leasing
consideration? 585.205 How will leases be mapped?
585.206 What is the lease size? 585.207–585.209 [Reserved]

Competitive Lease Process

585.210 How does BOEM initiate the competitive leasing process? 585.211 What is the process for competitive
issuance of leases? 585.212 What is the process BOEM will
follow if there is reason to believe that competitors have withdrawn before the
Final Sale Notice is issued? 585.213 What must I submit in response to a Request for Interest or a Call for
Information and Nominations?
585.214 What will BOEM do with information from the Requests for

Information or Calls for Information and

Nominations?
585.215 What areas will BOEM offer in a

lease sale?

585.216 What information will BOEM publish in the Proposed Sale Notice and

Final Sale Notice? 585.217–585.219 [Reserved]

Competitive Lease Award Process

585.220 What auction format may BOEM

use in a lease sale? 585.221 What bidding systems may BOEM

use for commercial leases and limited

leases? 585.222 What does BOEM do with my bid?

585.223 What does BOEM do if there is a tie for the highest bid? 585.224 What happens if BOEM accepts my

bid? 585.225 What happens if my bid is rejected, and what are my appeal rights? 585.226–585.229 [Reserved]

Noncompetitive Lease Award Process

585.230 May I request a lease if there is no

Call? 585.231 How will BOEM process my unsolicited request for a noncompetitive

lease? 585.232 May I acquire a lease noncompetitively after responding to a Request for Interest or Call for

Information and Nominations? 585.233 [Reserved] 585.234 [Reserved]

Commercial and Limited Lease Terms

585.235 If I have a commercial lease, how long will my lease remain in effect? 585.236 If I have a limited lease, how long will my lease remain in effect?

585.237 What is the effective date of a

lease? 585.238 Are there any other renewable energy research activities that will be

allowed on the OCS?

**Subpart C—Rights-of-Way Grants and Rights-of-Use and Easement Grants for**  **Renewable Energy Activities**

ROW Grants and RUE Grants

585.300 What types of activities are authorized by ROW grants and RUE grants issued under this part? 585.301 What do ROW grants and RUE grants include? 585.302 What are the general requirements for ROW grant and RUE grant holders? 585.303 How long will my ROW grant or RUE grant remain in effect? 585.304 [Reserved]

Obtaining ROW Grants and RUE Grants

585.305 How do I request an ROW grant or RUE grant? 585.306 What action will BOEM take on my request?
585.307 How will BOEM determine whether competitive interest exists for ROW grants and RUE grants?

585.308 How will BOEM conduct an auction for ROW grants and RUE grants?

585.309 When will BOEM issue a noncompetitive ROW grant or RUE grant?
585.310 What is the effective date of an ROW grant or RUE grant? 585.311–585.314 [Reserved]

Financial Requirements for ROW Grants

and RUE Grants

585.315 What deposits are required for a competitive ROW grant or RUE grant? 585.316 What payments are required for ROW grants or RUE grants?

**Subpart D—Lease and Grant Administration**

Noncompliance and Cessation Orders

585.400 What happens if I fail to comply with this part?


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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]

Lease or Grant Termination

585.432 When does my lease or grant

terminate? 585.433 What must I do after my lease or grant terminates? 585.434 [Reserved]

Lease or Grant Relinquishment

585.435 How can I relinquish a lease or a grant or parts of a lease or grant?

Lease or Grant Contraction

585.436 Can BOEM require lease or grant

contraction?

Lease or Grant Cancellation

585.437 When can my lease or grant be

canceled? **Subpart E—Payments and Financial Assurance Requirements** 

Payments

585.500 How do I make payments under this part? 585.501 What deposits must I submit for a competitively issued lease, ROW grant, or RUE grant? 585.502 What initial payment requirements must I meet to obtain a noncompetitive lease, ROW grant, or RUE grant? 585.503 What are the rent and operating fee requirements for a commercial lease? 585.504 How are my payments affected if I develop my lease in phases? 585.505 What are the rent and operating fee requirements for a limited lease? 585.506 What operating fees must I pay on

a commercial lease? 585.507 What rent payments must I pay on a project easement? 585.508 What rent payments must I pay on ROW grants or RUE grants associated with renewable energy projects? 585.509 Who is responsible for submitting lease or grant payments to BOEM? 585.510 May BOEM reduce or waive my lease or grant payments? 585.511–585.514 [Reserved]

Financial Assurance Requirements for

Commercial Leases

585.515 What financial assurance must I provide when I obtain my commercial

lease?

585.516 What are the financial assurance requirements for each stage of my

commercial lease?

585.517 How will BOEM determine the amounts of the supplemental and decommissioning financial assurance requirements associated with

commercial leases? 585.518 [Reserved] 585.519 [Reserved]

Financial Assurance for Limited Leases, ROW Grants, and RUE Grants

585.520 What financial assurance must I provide when I obtain my limited lease, ROW grant, or RUE grant? 585.521 Do my financial assurance requirements change as activities progress on my limited lease or grant?

585.522–585.524 [Reserved]

Requirements for Financial Assurance

Instruments
585.525 What general requirements must a

financial assurance instrument meet?

585.526 What instruments other than a surety bond may I use to meet the financial assurance requirement? 585.527 May I demonstrate financial strength and reliability to meet the financial assurance requirement for lease or grant activities? 585.528 May I use a third-party guaranty to meet the financial assurance requirement for lease or grant activities? 585.529 Can I use a lease- or grant-specific decommissioning account to meet the financial assurance requirements related to decommissioning? Changes in Financial Assurance

585.530 What must I do if my financial assurance lapses? 585.531 What happens if the value of my

financial assurance is reduced? 585.532 What happens if my surety wants to terminate the period of liability of my

bond? 585.533 How does my surety obtain cancellation of my bond? 585.534 When may BOEM cancel my bond? 585.535 Why might BOEM call for forfeiture of my bond?

585.536 How will I be notified of a call for

forfeiture? 585.537 How will BOEM proceed once my bond or other security is forfeited? 585.538 [Reserved] 585.539 [Reserved]

Revenue Sharing with States

585.540 How will BOEM equitably

distribute revenues to States? 585.541 What is a qualified project for revenue sharing purposes? 585.542 What makes a State eligible for payment of revenues? 585.543 Example of how the inverse

distance formula works.

**Subpart F—Plans and Information Requirements** 

585.600 What plans and information must I

submit to BOEM before I conduct activities on my lease or grant? 585.601 When am I required to submit my plans to BOEM?

585.602 What records must I maintain? 585.603 [Reserved] 585.604 [Reserved]

Site Assessment Plan and Information Requirements for Commercial Leases

585.605 What is a Site Assessment Plan (SAP)? 585.606 What must I demonstrate in my

SAP? 585.607 How do I submit my SAP? 585.608 [Reserved] 585.609 [Reserved]

Contents of the Site Assessment Plan

585.610 What must I include in my SAP?

585.611 What information must I submit with my SAP to assist BOEM in complying with NEPA and other relevant

laws? 585.612 How will my SAP be processed for Federal consistency under the Coastal Zone Management Act? 585.613 How will BOEM process my SAP?

Activities Under an Approved SAP

585.614 When may I begin conducting activities under my approved SAP? 585.615 What other reports or notices must I submit to BOEM under my approved

SAP? 585.616 [Reserved] 585.617 What activities require a revision to my SAP, and when will BOEM approve

the revision? 585.618 What must I do upon completion of approved site assessment activities? 585.619 [Reserved]


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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

585.645 What must I include in my GAP?

585.646 What information and certifications must I submit with my GAP to assist BOEM in complying with

NEPA and other relevant laws? 585.647 How will my GAP be processed for Federal consistency under the Coastal Zone Management Act? 585.648 How will BOEM process my GAP? 585.649 [Reserved]

Activities Under an Approved GAP

585.650 When may I begin conducting activities under my GAP? 585.651 When may I construct complex or significant OCS facilities on my limited lease or any facilities on my project easement proposed under my GAP? 585.652 How long do I have to conduct activities under an approved GAP? 585.653 What other reports or notices must I submit to BOEM under my approved

GAP? 585.654 [Reserved] 585.655 What activities require a revision to my GAP, and when will BOEM approve

the revision?

585.656 What must I do if I cease activities approved in my GAP before the end of my term? 585.657 What must I do upon completion of approved activities under my GAP?

Cable and Pipeline Deviations

585.658 Can my cable or pipeline construction deviate from my approved

COP or GAP? 585.659 What requirements must I include in my SAP, COP, or GAP regarding air quality?

**Subpart G—Facility Design, Fabrication,**

**and Installation**

Reports
585.700 What reports must I submit to BOEM before installing facilities described in my approved SAP, COP, or

GAP? 585.701 What must I include in my Facility Design Report? 585.702 What must I include in my Fabrication and Installation Report? 585.703 What reports must I submit for project modifications and repairs? 585.704 [Reserved]

Certified Verification Agent

585.705 When must I use a Certified Verification Agent (CVA)?

585.706 How do I nominate a CVA for BOEM approval? 585.707 What are the CVA’s primary duties for facility design review? 585.708 What are the CVA’s or project engineer’s primary duties for fabrication

and installation review? 585.709 When conducting onsite fabrication inspections, what must the CVA or project engineer verify? 585.710 When conducting onsite installation inspections, what must the CVA or project engineer do? 585.711 [Reserved] 585.712 What are the CVA’s or project engineer’s reporting requirements?
585.713 What must I do after the CVA or project engineer confirms conformance

with the Fabrication and Installation Report on my commercial lease? 585.714 What records relating to SAPs, COPs, and GAPs must I keep?

**Subpart H—Environmental and Safety Management, Inspections, and Facility** 
**Assessments for Activities Conducted Under SAPs, COPs and GAPs** 

585.800 How must I conduct my activities to comply with safety and environmental requirements? 585.801 How must I conduct my approved activities to protect marine mammals, threatened and endangered species, and designated critical habitat?

585.802 What must I do if I discover a potential archaeological resource while conducting my approved activities? 585.803 How must I conduct my approved activities to protect essential fish habitats

identified and described under the Magnuson-Stevens Fishery Conservation and Management Act? 585.804–585.809 [Reserved]

Safety Management Systems

585.810 What must I include in my Safety Management System? 585.811 When must I follow my Safety Management System? 585.812 [Reserved]

Maintenance and Shutdowns

585.813 When do I have to report removing equipment from service? 585.814 [Reserved]

Equipment Failure and Adverse

Environmental Effects

585.815 What must I do if I have facility damage or an equipment failure?

585.816 What must I do if environmental or other conditions adversely affect a cable, pipeline, or facility? 585.817–585.819 [Reserved]

Inspections and Assessments

585.820 Will BOEM conduct inspections?

585.821 Will BOEM conduct scheduled and unscheduled inspections?

585.822 What must I do when BOEM conducts an inspection? 585.823 Will BOEM reimburse me for my expenses related to inspections?

585.824 How must I conduct 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?

**Subpart J—Rights of Use and Easement for Energy- and Marine-Related Activities Using**  **Existing OCS Facilities**

Regulated Activities

585.1000 What activities does this subpart regulate? 585.1001–585.1003 [Reserved]

Requesting an Alternate Use RUE

585.1004 What must I do before I request an

Alternate Use RUE? 585.1005 How do I request an Alternate Use

RUE?
585.1006 How will BOEM decide whether

to issue an Alternate Use RUE? 585.1007 What process will BOEM use for competitively offering an Alternate Use

RUE? 585.1008 [Reserved] 585.1009 [Reserved]

Alternate Use RUE Administration

585.1010 How long may I conduct activities

under an Alternate Use RUE? 585.1011 What payments are required for

an Alternate Use RUE?

585.1012 What financial assurance is required for an Alternate Use RUE?

585.1013 Is an Alternate Use RUE assignable? 585.1014 When will BOEM suspend an

Alternate Use RUE? 585.1015 How do I relinquish an Alternate

Use RUE?
585.1016 When will an Alternate Use RUE

be cancelled? 585.1017 [Reserved]

Decommissioning an Alternate Use RUE

585.1018 Who is responsible for decommissioning an OCS facility subject

to an Alternate Use RUE? 585.1019 What are the decommissioning requirements for an Alternate Use RUE?

Authority: 43 U.S.C. 1331 et seq., 43 U.S.C.

1337.

**Subpart A—General Provisions**

**§ 585.100 Authority.**

The authority for this part derives
from amendments to subsection 8 of the Outer Continental Shelf Lands Act (OCS Lands Act) (43 U.S.C. 1337), as set forth in section 388(a) of the Energy Policy Act of 2005 (EPAct) (Pub. L. 109–58). The Secretary of the Interior delegated to the Bureau of Ocean Energy Management (BOEM) the authority to regulate activities under section 388(a) of the EPAct. These regulations specifically apply to activities that:

(a) Produce or support production, transportation, or transmission of energy from sources other than oil and gas; or

(b) Use, for energy-related purposes or
for other authorized marine-related purposes, facilities currently or previously used for activities authorized
under the OCS Lands Act.

**§ 585.101 What is the purpose of this part?**

The purpose of this part is to: (a) Establish procedures for issuanceand 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 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


### 64732 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

(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?** 

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 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.

**§ 585.107 How do I show that I am qualified to be a lessee or grant holder?** 

(a) You must demonstrate your technical and financial capability to construct, operate, maintain, and terminate/decommission projects for which you are requesting authorization.
Documentation can include:

(1) Descriptions of international or domestic experience with renewable energy projects or other types of electric-energy-related projects; and

(2) Information establishing access to sufficient capital to carry out development.

(b) An individual must submit a written statement of citizenship status attesting to U.S. citizenship. It does not need to be notarized nor give the age of individual. A resident alien may submit a photocopy of the Immigration and Naturalization Service form evidencing legal status of the resident alien.

(c) A corporation or association must submit evidence, as specified in the table in paragraph (d) of this section, acceptable to BOEM that:

(1) It is qualified to hold leases or grants under this part;

(2) It is authorized to conduct business under the laws of its State;

(3) It is authorized to hold leases or grants on the OCS under the operating rules of its business; and

(4) The persons holding the titles
listed are authorized to bind the corporation or association when conducting business with BOEM.

(d) Acceptable evidence under paragraph (c) of this section includes, but is not limited to the following:

Requirements to qualify to hold leases or grants on the OCS: Corp. Ltd. Prtnsp. Gen. Prtnsp. LLC Trust

(1) Original certificate or certified copy from the State of incorporation

stating the name of the corporation exactly as it must appear on all legal documents. XX .................... .................... .................... .................... (2) Certified statement by Secretary/Assistant Secretary over corporate

seal, certifying that the corporation is authorized to hold OCS

leases. XX .................... .................... .................... ....................


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Requirements to qualify to hold leases or grants on the OCS: Corp. Ltd. Prtnsp. Gen. Prtnsp. LLC Trust

(3) Evidence of authority of titled positions to bind corporation, certified

by Secretary/Assistant Secretary over corporate seal, including the following: XX .................... .................... .................... ....................

(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. .................... XX XX XX .................... (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. .................... XX XX XX ....................(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. .................... XX XX XX ....................(7) Statements from each partner or LLC member indicating the following: .................... XX XX XX ....................

(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: .................... XX .................... .................... ....................

(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. .................... XX XX XX ....................(10) Listing of members of LLC certified by Secretary/Assistant Secretary or any member or manager of LLC. .................... .................... .................... XX .................... (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. .................... .................... .................... .................... XX (12) Statement indicating the law under which the trust is established

and that the trust is authorized to hold OCS leases or grants. .................... .................... .................... .... ................ XX

(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.

**§ 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 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. **§ 585.111 When and how does BOEM charge me processing fees on a case-by** 

**case basis?**

(a) BOEM will charge a processing fee on a case-by-case basis under the procedures in this section with regard to any application or request under this part if we decide at any time that the preparation of a particular document or study is necessary for the application or request and it will have a unique processing cost, such as the preparation of an Environmental Assessment (EA) or Environmental Impact Statement (EIS).

(1) Processing costs will include contract oversight and efforts to review and approve documents prepared by contractors, whether the contractor is paid directly by the applicant or through BOEM.

(2) We may apply a standard overhead rate to direct processing costs.

(b) We will assess the ongoing processing fee for each individual application or request according to the following procedures:


### 64734 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

(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. **§ 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 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


### 64735 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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 electricity or other energy product for sale, distribution, or other commercial use exceeding a limit specified in the
lease.

Marine environment means the physical, atmospheric, and biological components, conditions, and factors that interactively determine the productivity, state, condition, and quality of the marine ecosystem. These include the waters of the high seas, the contiguous zone, transitional and intertidal areas, salt marshes, and
wetlands within the coastal zone and on
the OCS.

Miles mean nautical miles, as opposed
to statute miles.

Natural resources include, without limiting the generality thereof, renewable energy, oil, gas, and all other minerals (as defined in section 2(q) of the OCS Lands Act), and marine animal and marine plant life.

Operator means the individual, corporation, or association having control or management of activities on the lease or grant under this part. The operator may be a lessee, grant holder, or a contractor designated by the lessee or holder of a grant under this part.

Outer Continental Shelf (OCS) means all submerged lands lying seaward and
outside of the area of lands beneath navigable waters, as defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301), whose subsoil and seabed appertain to the United States and are subject to its jurisdiction and control.

Person means, in addition to a natural person, an association (including partnerships and joint ventures); a Federal agency; a State; a political subdivision of a State; a Native American Tribal government; or a private, public, or municipal corporation.

Project, for the purposes of defining the source of revenues to be shared, means a lease ROW, RUE, or Alternate
Use RUE on which the activities authorized under this part are
conducted on the OCS. The term ‘‘project’’ may be used elsewhere in this
rule to refer to these same authorized activities, the facilities used to conduct these activities, or to the geographic area of the project, i.e., the project area.

Project area means the geographic surface leased, or granted, for the purpose of a specific project. If OCS acreage is granted for a project under some form of agreement other than a lease (i.e., a ROW, RUE, or Alternate Use RUE issued under this part), the Federal acreage granted would be considered the project area. To avoid distortions in the calculation of the geometric center of the project area, project easements issued under this part are not considered part of the qualified project’s

area.

Project easement means an easement to which, upon approval of your Construction and Operations Plan (COP) or General Activities Plan (GAP), you are entitled as part of the lease for the purpose of installing, gathering, transmission, and distribution cables, pipelines, and appurtenances on the OCS as necessary for the full enjoyment
of the lease.

Renewable Energy means energy resources other than oil and gas and minerals as defined in 30 CFR part 580. Such resources include, but are not limited to, wind, solar, and ocean waves, tides, and current.

Revenues mean bonuses, rents, operating fees, and similar payments made in connection with a project or project area. It does not include
administrative fees such as those assessed for cost recovery, civil penalties, and forfeiture of financial

assurance.

Right-of-use and easement (RUE)
grant means an easement issued by BOEM under this part that authorizes use of a designated portion of the OCS to support activities on a lease or other use authorization for renewable energy
activities. The term also means the area covered by the authorization.

Right-of-way (ROW) grant means an authorization issued by BOEM under this part to use a portion of the OCS for
the construction and use of a cable or pipeline for the purpose of gathering, transmitting, distributing, or otherwise transporting electricity or other energy product generated or produced from renewable energy, but does not constitute a project easement under this part. The term also means the area covered by the authorization.

Secretary means the Secretary of the
Interior or an official authorized to act on the Secretary’s behalf.

Significant archaeological resource means an archaeological resource that meets the criteria of significance for eligibility for listing in the National Register of Historic Places, as defined in

36 CFR 60.4 or its successor.

Site assessment activities mean those
initial activities conducted to characterize a site on the OCS, such as resource assessment surveys ( e.g., meteorological and oceanographic) or technology testing, involving the
installation of bottom-founded facilities.

You and your refer to an applicant, lessee, the operator, a designated agent of the lessee(s) or designated operator, ROW grant holder, RUE grant holder, or Alternate Use RUE grant holder under this part, or the possessive of each, depending on the context.


### 64736 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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. (2) Limited lease ....................................................................................... At 3 years after the lease terminates. (3) ROW or RUE grant ............................................................................. At the earliest of: (i) 10 years after the approval of the grant; (ii) Grant termination; or (iii) 3 years after the completion of construction activities.

(c) After considering any objections from the submitter, if we determine that
release of such data and information
will result in:

(1) No substantial competitive harm or disclosure of trade secrets, then the
data and information will be released.

(2) Substantial competitive harm or disclosure of trade secrets, then the data
and information will not be released at that time but will be subject to further review every 3 years thereafter.

**§ 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. (2) Subpart B—Issuance of OCS Renewable Energy 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. (3) Subpart C—ROW Grants and RUE Grants for Renewable Energy

Activities. To issue ROW grants and RUE grants for OCS renewable energy activities that are not associated with a BOEM-issued renewable energy lease. (4) Subpart D—Lease and Grant Administration ..................................... To ensure compliance with regulations pertaini ng to a lease or grant; assignment and designation of operator; and suspension, renewal, termination, relinquishment, and cancellation of leases and grants.(5) Subpart E—Payments and Financial Assurance Requirements ........ To ensure that payments and financial assurance payments for renewable energy leases comply with subpart E. (6) Subpart F—Plans and Information Requirements .............................. 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. (7) Subpart G—Facility Design, Fabrication, and Installation .................. To enable BOEM to review the final design, fabrication, and installationof facilities on a lease or grant to ensure that these facilities are designed, fabricated, and installed according to appropriate standardsin compliance with BOEM regulations, and where applicable, the approved plan.


### 64737 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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 withother Federal laws, these regulations, the lease or grant, and approved plans. (9) Subpart I—Decommissioning ............................................................. To determine that decommissioning activities comply with regulatoryrequirements and approvals. To ensure that site clearance and platform or pipeline removal are properly performed to protect marine life

and the environment and do not conflict with other users of the OCS. (10) Subpart J—RUEs for Energy and Marine-Related Activities Using

Existing OCS Facilities. 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.

**§ 585.115 Documents incorporated by**

**reference.**

(a) BOEM is incorporating by
reference the documents listed in the table in paragraph (e) of this section. The Director of the Federal Register has approved this incorporation by reference according to 5 U.S.C. 552(a) and 1 CFR part 51.

(1) BOEM will publish, as a rule, any changes in the documents incorporated by reference in the Federal Register

.

(2) BOEM may amend by rule the list of industry standards incorporated by
reference of the document effective without prior opportunity for public
comment when BOEM determines that
the revisions to a document result in safety improvements or represent new industry standard technology and do not impose undue costs on the affected parties; and (3) BOEM may make a rule, effective immediately, amending the list of industry standards incorporated by reference if it determines good cause exists for doing so under 5 U.S.C. 553.

(b) BOEM is incorporating each document or specific portion by
reference in the sections noted. The entire document is incorporated by reference, unless the text of the corresponding sections in this part calls for compliance with specific portions of the listed documents. In each instance, the applicable document is the specific edition, or specific edition and supplement, or specific addition and
addendum cited in this section.

(c) You may comply with a later edition of a specific document incorporated by reference, only if:

(1) You show that complying with the later edition provides a degree of protection, safety, or performance equal
to or better than what would be achieved by compliance with the listed edition; and

(2) You obtain the prior written approval for alternative compliance
from the authorized BOEM official.

(d) You may inspect these documents at the Bureau of Ocean Energy Management, 381 Elden Street, Room 3313, Herndon, Virginia, 703–787–1605;
or at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, call 202–741–6030,
or go to: http://www.archives.gov/ federal

_register/
code

_of

_ federal

_regulations/
ibr

_locations.html. You may obtain the documents from the publishing organizations at the addresses given in the following table:

For . . . Write to . . .

API Recommended Practices .................................................................. American Petroleum Institute, 1220 L Street, NW., Washington, DC

20005–4070. http://www.api.org/publications/

(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. 30 CFR 585.825

**§ 585.116 Requests for information on the state of the offshore renewable energy**  **industry.**

(a) The Director may, from time to time, and at his discretion, solicit information from industry and other relevant stakeholders (including State and local agencies), as necessary, to
evaluate the state of the offshore renewable energy industry, including the identification of potential challenges
or obstacles to its continued development. Such requests for information may relate to the identification of environmental, technical, regulatory, or economic matters that promote or detract from continued development of renewable energy technologies on the OCS. From the information received, the Director may evaluate potential refinements to the OCS Alternative Energy Program that promote development of the industry in a safe and environmentally responsible manner, and that ensure fair

value for use of the Nation’s OCS.

(b) BOEM may make such requests for information on a regional basis, and may tailor the requests to specific types of renewable energy technologies.

(c) BOEM will publish such requests for information by the Director in the Federal Register

.


### 64738 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

**§ 585.117 [Reserved]**

**§ 585.118 What are my appeal rights?**

(a) Any party adversely affected by a
BOEM official’s final decision or order issued under the regulations of this part may appeal that decision or order to the Interior Board of Land Appeals. The appeal must conform with the procedures found in 30 CFR part 590 and 43 CFR part 4, subpart E. Appeal of a final decision for bid acceptance is covered under paragraph (c) of this

section.

(b) A decision will remain in full force and effect during the period in which an appeal may be filed and during an appeal, unless a stay is granted pursuant to 43 CFR part 4.

(c) Our decision on a bid is the final action of the Department, except that an unsuccessful bidder may apply for reconsideration by the Director.

(1) A bidder whose bid we reject may file a written request for reconsideration with the Director within 15 days of the date of the receipt of the notice of rejection, accompanied by a statement of reasons, with one copy to us. The Director will respond in writing either affirming or reversing the decision.

(2) The delegation of review authority given to the Office of Hearings and Appeals does not apply to decisions on high bids for leases or grants under this
part.

**Subpart B—Issuance of OCS Renewable Energy Leases** 

General Lease Information

**§ 585.200 What rights are granted with a lease issued under this part?** 

(a) A lease issued under this part grants the lessee the right, subject to obtaining the necessary approvals, including but not limited to those required under the FERC hydrokinetic licensing process, and complying with all provisions of this part, to occupy, and install and operate facilities on, a designated portion of the OCS for the purpose of conducting:

(1) Commercial activities; or (2) Other limited activities that support, result from, or relate to the production of energy from a renewable

energy source.

(b) A lease issued under this part confers on the lessee the right to one or more project easements without further competition for the purpose of installing gathering, transmission, and distribution cables; pipelines; and appurtenances on the OCS as necessary for the full enjoyment of the lease.

(1) You must apply for the project easement as part of your COP or GAP, as provided under subpart F of this part;
and

(2) BOEM will incorporate your approved project easement in your lease
as an addendum.

(c) A commercial lease issued under this part may be developed in phases, with BOEM approval as provided in § 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 What types of leases will BOEM**

**issue?**

BOEM may issue leases on the OCS for the assessment and production of renewable energy and may authorize a combination of specific activities. We may issue commercial leases or limited
leases.

**§ 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. **§ 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


### 64739 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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.

**§ 585.212 What is the process BOEM will**

**follow if there is reason to believe that competitors have withdrawn before the** 

**Final Sale Notice is issued?**

BOEM may decide to end the competitive process before the Final
Sale Notice if we have reason to believe that competitors have withdrawn and competition no longer exists. We will issue a second public notice of Request
for Interest and consider comments
received to confirm that there is no competitive interest.

(a) If, after reviewing comments in response to the notice of Request for Interest, BOEM determines that there is no competitive interest in the lease area, and one party wishes to acquire a lease, we will discontinue the competitive process and will proceed with the noncompetitive process set forth in § 585.231(d) through (i). Under the 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.

**§ 585.214 What will BOEM do with information from the Requests for** 

**Information or Calls for Information and**

**Nominations?**

BOEM will use the information received in response to the Requests or
Calls to:

(a) Identify the lease area; (b) Develop options for the environmental analysis and leasing provisions (stipulations, payments, terms, and conditions); and

(c) Prepare appropriate documentation to satisfy applicable Federal requirements, such as NEPA, CZMA, the ESA, and the MMPA.

**§ 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 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:


### 64740 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

Type of auction Bid variable Bidding process

(1) Sealed bidding .............................................. A cash bonus or an operating fee rate ............ One sealed bidper company per lease or packaged bidding unit. (2) Ascending bidding ........................................ A cash bonus or an operating fee rate ............ Continuous bidding per lease.(3) Two-stage bidding (combination of ascending and sealed bidding). An operating fee rate in one, both, or neither stage and a cash bonus in one, both, or neither stage. 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. (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 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) .................................. Cash bonus. (2) Constant operating fee rate with fixed 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. (3) Sliding operating fee rate with a fixed cash bonus ............................ A fee rate used in the formula in § 585.506 toset the operating fee for the first year of the operations term of your lease. The fee rate for subsequent years changes by a mathematical function we specify in

the Final Sale Notice. (4) Cash bonus and constant operating fee rate ..................................... Cash bonus and operating fee rate as stated in paragraph (2) of this section (two-stage auction format only). (5) Cash bonus and sliding operating fee rate ........................................ Cash bonus and operating fee rate as stated in paragraph (3) of this section (two-stage auction format only). (6) Multiple-factor combination of nonmonetary and monetary factors ... 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.

(b) For limited leases, the bid variable will be a cash bonus, with a minimum bid as we specify in the Final Sale

Notice.

**§ 585.222 What does BOEM do with my**

**bid?**

(a) If sealed bidding is used: (1) We open the sealed bids at the place, date, and hour specified in the Final Sale Notice for the sole purpose of publicly announcing and recording the bids. We do not accept or reject any bids
at that time.

(2) We reserve the right to reject any and all high bids, including a bid for any proposal submitted under the multiple-factor bidding format, regardless of the amount offered or bidding system used. The reasons for the rejection of a winning bid may include, but are not necessarily limitedto, insufficiency, illegality, anticompetitive behavior, administrative error, and the presence of unusual bidding patterns. We intend to accept or reject all high bids within 90 days, but we may extend that time if necessary.

(b) If we use ascending bidding, we may, in the Final Sale Notice, reserve the right to accept the winning bid solely based on its being the highest bid submitted by a qualified bidder (qualified to be an OCS lessee under § 585.107).

(c) If we use two-stage bidding and

the auction concludes with

(i) An ascending bidding stage, the winning bid will be determined as stated in paragraph (b) of this section; or

(ii) A sealed bidding stage, the winning bid will be determined as stated in paragraph (a) of this section.

(d) If we use multiple-factor bidding, determination of the winning bid for any proposal submitted will be made by a panel composed of members selected by BOEM. The details of the process

will be described in the Final Sale

Notice. (e) We will send a written notice of our decision to accept or reject bids to all bidders whose deposits we hold.

**§ 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 What happens if BOEM accepts my bid?** 

If we accept your bid, we will send you a notice with three copies of the
lease form.

(a) Within 10 business days after you receive the lease copies, you must:

(1) Execute the lease;


### 64741 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

(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.

**§ 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 May I request a lease if there is**

**no Call?**

You may submit an unsolicited request for a commercial lease or a limited lease under this part. Your unsolicited request must contain the following information:

(a) The area you are requesting for
lease.

(b) A general description of your objectives and the facilities that you would use to achieve those objectives.

(c) A general schedule of proposed activities including those leading to commercial operations.

(d) Available and pertinent data and information concerning renewable energy and environmental conditions in the area of interest, including energy
and resource data and information used
to evaluate the area of interest. BOEM
will withhold trade secrets and
commercial or financial information that is privileged or confidential from public disclosure under exemption 4 of the FOIA and as provided in § 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 (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


### 64742 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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 issuednoncompetitively does not have a preliminary 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.

(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 siteassessment term begins when BOEM approves your SAP or SAP/COP. 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.

(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 theSAP/COP, or when fabrication and installation commence, whichever is earlier. ...................................................................... The lease renewal request must meet the requirements, as provided in §§ 585.425 through 585.429.

(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. ...................................................................... We may order or grant a suspension of the operations term, as provided in §§ 585.415 through 585.421.

(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. **§ 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 aGAP. 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 ofthis 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.

(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. ...................................................................... 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. (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. We may order or grant a suspension of the operations term as provided in §§ 585.415 through 585.421.

(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. **§ 585.237 What is the effective date of a**

**lease?**

(a) A lease issued under this part must

be dated and becomes effective as of the first day of the month following the date a lease is signed by the lessor. (b) If the lessee submits a written request and BOEM approves, a lease may be dated and become effective the first day of the month in which it is signed by the lessor.


### 64743 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

**§ 585.238 Are there any other renewable energy research activities that will be** 

**allowed on the OCS?**

(a) The Director may issue OCS leases, ROW grants, and RUE grants to a Federal agency or a State for renewable energy research activities that support the future production, transportation, or transmission of renewable energy.

(b) In issuing leases, ROW grants, and RUE grants to a Federal agency or a State on the OCS for renewable energy research activities under this provision,

BOEM will coordinate and consult with other relevant Federal agencies, any other affected State(s), affected local government executives, and affected

Indian Tribes.

(c) BOEM may issue leases, RUEs, and ROWs for research activities managed by a Federal agency or a State only in

areas for which the Director has determined, after public notice and opportunity to comment, that no competitive interest exists.

(d) The Director and the head of the Federal agency or the Governor of a requesting State, or their authorized representatives, will negotiate the terms

and conditions of such renewable energy leases, RUEs, or ROWs under this provision on a case-by-case basis. The framework for such negotiations,

and standard terms and conditions of such leases, RUEs, or ROWs may be set forth in a memorandum of agreement (MOA) or other agreement between BOEM and a Federal agency or a State. The MOA must include the agreement of the head of the Federal agency or the

Governor to assure that all subcontractors comply with these regulations, other applicable laws, and

terms and conditions of such leases or
grants.

(e) Any lease, RUE, or ROW that BOEM issues to a Federal agency or to

a State that authorizes access to an area
of the OCS for research activities managed by a Federal agency or a State
must include:

(1) Requirements to comply with all applicable Federal laws; and

(2) Requirements to comply with these regulations, except as otherwise provided in the lease or grant.

(f) BOEM will issue a public notice of any lease, RUE, ROW issued to a Federal agency or to a State, or an approved MOA for such research

activities.

(g) BOEM will not charge any fees for the purpose of ensuring a fair return for
the use of such research areas on the

OCS. **Subpart C—Rights-of-Way Grants and Rights-of-Use and Easement Grants**  **for Renewable Energy Activities**

ROW Grants and RUE Grants

**§ 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 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.

**§ 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. **§§ 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**

Noncompliance and Cessation Orders

**§ 585.400 What happens if I fail to comply with this part?** 

(a) BOEM may take appropriate corrective action under this part if you fail to comply with applicable provisions of Federal law, the regulations in this part, other applicable regulations, any order of the Director, the provisions of a lease or grant issued under this part, or the requirements of an approved plan or other approval under this part.

(b) BOEM may issue to you a notice of noncompliance if we determine that
there has been a violation of the regulations in this part, any order of the Director, or any provision of your lease, grant or other approval issued under this part. When issuing a notice of noncompliance, BOEM will serve you at your last known address.

(c) A notice of noncompliance will tell you how you failed to comply with this part, any order of the Director, and/ or the provisions of your lease, grant or other approval, and will specify what you must do to correct the noncompliance and the time limits within which you must act.

(d) Failure of a lessee, operator, or grant holder under this part to take the actions specified in a notice of noncompliance within the time limit specified provides the basis for BOEM to issue a cessation order as provided in § 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.

**§ 585.401 When may BOEM issue a**

**cessation order?**

(a) BOEM may issue a cessation order during the term of your lease or grant when you fail to comply with an applicable law; regulation; order; or provision of a lease, grant, plan, or other BOEM approval under this part. Except as provided in § 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.

**§ 585.402 What is the effect of a cessation**

**order?**

(a) Upon receiving a cessation order, you must cease all activities on your lease or grant, as specified in the order. BOEM may authorize certain activities during the period of the cessation order.

(b) A cessation order will last for the period specified in the order or as otherwise specified by BOEM. If BOEM
determines that the circumstances giving rise to the cessation order cannot
be resolved within a reasonable time period, the Secretary may initiate cancellation of your lease or grant, as provided in § 585.437.

(c) A cessation order does not extend the term of your lease or grant for the


### 64745 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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.

**§ 585.406 Who is responsible for fulfilling lease and grant obligations?** 

(a) When you are not the sole lessee or grantee, you and your co-lessee(s) or co-grantee(s) are jointly and severally responsible for fulfilling your obligations under the lease or grant and the provisions of this part, unless otherwise provided in these regulations.

(b) If your designated operator fails to fulfill any of your obligations under the lease or grant and this part, BOEM mayrequire 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 May I assign my lease or grant**

**interest?**

(a) You may assign all or part of your lease or grant interest, including record title, subject to BOEM approval under this subpart. Each instrument that
creates or transfers an interest must describe the entire tract or describe by officially designated subdivisions the interest you propose to create or
transfer.

(b) You may assign a lease or grant interest by submitting one paper copy and one electronic copy of an assignment application to BOEM. The assignment application must include:

(1) BOEM-assigned lease or grant number;

(2) A description of the geographic area or undivided interest you are assigning;

(3) The names of both the assignor and the assignee, if applicable;

(4) The names and telephone numbers of the contacts for both the assignor and the assignee;

(5) The names, titles, and signatures of the authorizing officials for both the assignor and the assignee;

(6) A statement that the assignee agrees to comply with and to be bound by the terms and conditions of the lease
or grant;

(7) The qualifications of the assignee to hold a lease or grant under § 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, 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.

**§ 585.417 When may BOEM order a suspension?** 

(a) BOEM may order a suspension under the following circumstances:

(1) When necessary to comply with judicial decrees prohibiting some or all activities under your lease;

(2) When continued activities pose an imminent threat of serious or irreparable harm or damage to natural resources; life (including human and wildlife); property; the marine, coastal, or human
environment; or sites, structures, or objects of historical or archaeological significance; or

(3) When the suspension is necessary for reasons of National security or
defense.

(b) If BOEM orders a suspension under paragraph (a)(2) of this section, and if you wish to resume activities, we may require you to conduct a 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.

**§ 585.418 How will BOEM issue a suspension?** 

(a) BOEM will issue a suspension order orally or in writing.

(b) BOEM will send you a written suspension order as soon as practicable after issuing an oral suspension order.

(c) The written order will explain the
reasons for its issuance and describe the effect of the suspension order on your lease or grant and any associated activities. BOEM may authorize certain activities during the period of the suspension, as set forth in the suspension order.

**§ 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 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 How long will a suspension be in**

**effect?**

A suspension will be in effect for the period specified by BOEM.

(a) BOEM will not approve a suspension request pursuant to § 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

**§ 585.425 May I obtain a renewal of my lease or grant before it terminates?** 

You may request renewal of the operations term of your lease or the original authorized term of your grant. BOEM, at its discretion, may approve a renewal request to conduct substantially similar activities as were originally authorized under the lease or grant. BOEM will not approve a renewal request that involves development of a type of renewable energy not originally authorized in the lease or grant. BOEM may revise or adjust payment terms of the original lease, as a condition of lease
renewal.

**§ 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

**§ 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. **§ 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. (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;


### 64748 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

(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 instrument. You may access the Pay.gov Web site through links on the BOEM

Offshore Web site at: http:// www.boem.gov/offshore or directly through Pay.gov at: https:// www.pay.gov/paygov/.

(b) For rent during the preliminary term, subsequent to the first 6-months rent, or the site assessment term; or operating fees during the operations term, you must make your payments as required in 30 CFR 1218.51 of this chapter.

(c) This table summarizes payments you must make for leases and grants, unless otherwise specified in the Final

Sale Notice:

Payment Amount Due date Payment mechanism Section reference

**Initial payments for leases**

(1) If your lease is issued

competitively, Bid Deposit .............. As set in Final Sale Notice/depends on

bid. With bid ................... Pay.Gov ................... § 585.501.

Bonus Balance ........ .................................. Lease issuance ....... 30 CFR 1218.51. (2) If your lease is issued

non-competitively. Acquisition Fee ........ $0.25 per acre, unless otherwise set by the Director. With application ....... Pay.gov .................... § 585.502.

(3) All leases ..................... Initial Rent ............... $3 per acre per year 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 ...... §§ 585.503 and

585.504. (5) If you have a project

easement. Rent ......................... Greater of $5 per

acre per year or $450 per year. When operations

term for associated lease starts, then annually. 30 CFR 1218.51 ...... § 585.507.

(7) If your commercial

lease is producing, Operating Fee .......... Determined by the

formula in § 585.506. Annually ................... 30 CFR 1218.51 ...... § 585.506.

**Payments for ROW grants and RUE grants** *

(8) All ROW grants and

RUE grants. Initial Rent ............... $70 per statute mile, and the greater of $5 per acre per year or $450 per

year. Grant Issuance ........ Pay.gov .................... § 585.508.

Subsequent Rent ..... .................................. Annually or in 5-year

batches. 30 CFR 1218.51.

* There is no acquisition fee for ROW grants or RUE grants.

**§ 585.501 What deposits must I submit for a competitively issued lease, ROW grant, or**  **RUE grant?**

(a) For a competitive lease or grant that we offer through sealed bidding, you must submit a deposit of 20 percent of the total bid amount, unless some other amount is specified in the Final
Sale Notice.

(b) For a competitive lease that we offer through ascending bidding, you must submit a deposit as established in
the Final Sale Notice.

(c) You must pay any balances on accepted high bids in accordance with the Final Sale Notice, this part, and your lease or grant instrument.

(d) The deposit will be forfeited for any successful bidder who fails to execute the lease within the prescribed time, or otherwise does not comply with the regulations concerning acquisition of a lease or grant or stipulations in the

Final Sale Notice. **§ 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


### 64749 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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 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.

**§ 585.504 How are my payments affected if I develop my lease in phases?** 

If you develop your commercial lease in phases, as approved by us in your COP under § 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. (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:

F (annual operating fee) = M (nameplate capacity) * H (hours per year) * c (capacity factor) * P (power price) * r (operating fee rate)

(c) BOEM will specify operating fee parameters in the Final Sale Notice for commercial leases issued competitively

and in the lease for those issued noncompetitively.

(1) Unless BOEM specifies otherwise, in the operating fee rate, ‘‘r’’ is 0.02 for each year the operating fee applies when you begin commercial generation of electricity. We may apply a different fee rate for new projects (i.e., a new generation based on new technology) after considering factors such as program objectives, state of the industry, project type, and project potential. Also, we may agree to reduce or waive the fee rate under § 585.510.

(2) The power price ‘‘P,’’ for each year when the operating fee applies, will be determined annually. The process by which the power price will be determined will be specified in the

Final Sale Notice and/or in the lease.

BOEM:

(i) Will use the most recent annual average wholesale power price in the State in which a project’s transmission cables make landfall, as published by the DOE, Energy Information Administration (EIA), or other publicly


### 64750 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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 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. **§ 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


### 64751 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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 reflectchanges 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. A $100,000 minimum, lease-specific financial assurance.

(2) Approve your SAP .............................................................................. A supplemental bond or other financial assurance, in an amount determined by BOEM, if upon reviewing your SAP, BOEM determines thata 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.(3) Approve your COP .............................................................................. A supplemental bond or other financial assurance, in an amount determined by BOEM based on the complexity, number, and location ofall facilities involved in your planned activities and commercial operation. The supplemental financial assurance requirement is in addition to your lease-specific bond and, if applicable, the previous supplement associated with SAP approval. (4) Allow you to install facilities approved in your COP ........................... 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.

(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?**

(a) BOEM will base the determination for the amounts of the SAP, COP, and decommissioning financial assurance requirements on estimates of the cost to meet all accrued lease obligations.

(b) We determine the amount of the supplemental and decommissioning financial assurance requirements on a case-by-case basis. The amount of the
financial assurance must be no less than the amount required to meet all lease obligations, including:

(1) The projected amount of rent and other payments due the Government over the next 12 months;

(2) Any past due rent and other
payments;

(3) Other monetary obligations; and (4) The estimated cost of facility decommissioning, as required by subpart I of this part.

(c) If your cumulative potential obligations and liabilities increase or decrease, we may adjust the amount of supplemental or the decommissioning
financial assurance.

(1) If we propose adjusting your financial assurance amount, we will notify you of the proposed adjustment and give you an opportunity to comment; and

(2) We may approve a reduced financial assurance amount if you request it and if the reduced amount that you request continues to be greater
than the sum of:

(i) The projected amount of rent and other payments due the Government over the next 12 months;

(ii) Any past due rent and other
payments;

(iii) Other monetary obligations; and (iv) The estimated cost of facility decommissioning.

**§§ 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 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 operatorprovides 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


### 64752 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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

**§ 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 http://www.fms.treas.gov/c570/.

(d) Your surety bond cannot exceed the underwriting limit listed in the current Treasury Circular 570, except as permitted therein.

(e) You and a qualified surety must execute your bond. When the surety is a corporation, an authorized corporate officer must sign the bond and attest to it over the corporate seal.

(f) You may not terminate the period of liability of your bond or cancel your bond, except as provided in this subpart. Bonds must continue in full force and effect even though an event
has occurred that could diminish or terminate a surety’s obligation under
State law.

(g) Your surety must notify you and BOEM within 5 business days after:

(1) It initiates any judicial or administrative proceeding alleging its insolvency or bankruptcy; or

(2) The Treasury decertifies the
surety.

**§ 585.526 What instruments other than a surety bond may I use to meet the financial**  **assurance requirement?**

(a) You may use other types of security instruments, if BOEM determines that such security protects BOEM to the same extent as the surety bond. BOEM will consider pledges of the following:

(1) U.S. Department of Treasury securities identified in 31 CFR part 225;

(2) Cash in an amount equal to the required dollar amount of the financial assurance, to be deposited and maintained in a Federal depository account of the U.S. Treasury by BOEM;

(3) Certificates of deposit or savings
accounts in a bank or financial institution organized or authorized to
transact business in the United States
with:

(i) Minimum net assets of $500,000,000; and

(ii) Minimum Bankrate.com Safe & Sound rating of 3 Stars, and Capitalization, Assets, Equity and Liquidity (CAEL) rating of 3 or less;

(4) Negotiable U.S. Government, State, and municipal securities or bonds having a market value of not less than the required dollar amount of the
financial assurance and maintained in a

Securities Investors Protection Corporation insured trust account by a licensed securities brokerage firm for the benefit of the BOEM;

(5) Investment-grade rated securities having a Standard and Poor’s rating of AAA or an equivalent rating from a nationally recognized securities rating service having a market value of not less than the required dollar amount of the
financial assurance and maintained in a

Securities Investors Protection Corporation insured trust account by a licensed securities brokerage firm for the benefit of BOEM; and (6) Insurance, if its form and function is such that the funding or enforceable pledges of funding are used to guarantee performance of regulatory obligations in the event of default on such obligations by the lessee. Insurance must have an A.M. Best rating of ‘‘superior’’ or an equivalent rating from a nationally recognized insurance rating service.

(b) If you use a Treasury security: (1) You must post 115 percent of your financial assurance amount;

(2) You must monitor the collateral value of your security. If the collateral value of your security as determined in accordance with the 31 CFR part 203 Collateral Margins Table (which can be
found at http://www.treasurydirect.gov ) falls below the required level of coverage, you must pledge additional security to provide 115 percent of the required amount; and

(3) You must include with your pledge authority for us to sell the security and use the proceeds if we determine that you have failed to comply with any of the terms and conditions of your lease or grant, any subsequent approval or authorization, or applicable regulations.

(c) If you use the instruments described in paragraphs (a)(4) or (a)(5) of this section, you must provide BOEM by the end of each calendar year a certified statement describing the nature
and market value of the instruments maintained in that account, and including any current statements or reports furnished by the brokerage firm to the lessee concerning the asset value
of the account.

**§ 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


### 64753 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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. (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 publi c accountant containing the accountant’s audit or review opinion of the statements. The report must be prepared in conformance with generally accepted accounting principles and contain no adverse opinion. (ii) Financial statement for completed quarter in the current FY ............. Your guarantor’s financial officer certifies to be correct. (iii) Additional information related to bonds, if requested by the Director Your guarantor’s financial officer certifies to be correct.

(4) Your guarantor’s total outstanding and proposed guarantees must not exceed 25 percent of its unencumbered
domestic net worth.

(c) Your guarantor must submit an agreement executed by the guarantor and all parties bound by the agreement. All parties are bound jointly and severally and must meet the qualifications set forth in § 585.107.

(1) When any party is a corporation, two corporate officers authorized to execute the guaranty agreement on behalf of the corporation must sign the
agreement.

(2) When any party is a partnership, joint venture, or syndicate, the guaranty agreement must bind each party who has a beneficial interest in your guarantor and provide that, upon BOEM demand under your guaranty, each party is jointly and severally liable for compliance with all terms and conditions of your lease(s) or grant(s) covered by the agreement.

(3) When forfeiture of the guaranty is called for, the agreement must provide that your guarantor will either bring your lease(s) or grant(s) into compliance or provide, within 7 days, sufficient funds to permit BOEM to complete

corrective action.

(4) The guaranty agreement must contain a confession of judgment, providing that, if we determine that you are, or your operator or operating rights owner is, in default, the guarantor must not challenge the determination and must remedy the default.

(5) If you fail, or your operator or operating rights owner fails, to comply with any law, term, or regulation, your guarantor must either take corrective action or provide, within 7 days or other agreed upon time period, sufficient funds for BOEM to complete corrective action. Such compliance must not reduce your guarantor’s liability.

(6) If your guarantor wants to terminate the period of liability, your guarantor must notify you and us at least 90 days before the proposed termination date, obtain our approval for termination of all or a specified portion of the guarantee for liabilities arising after that date, and remain liable for all your work performed during the period the agreement is in effect.

(7) Each guaranty submitted pursuant
to this section is deemed to contain all the above terms, even if they are not actually in the agreement.

(d) Before the termination of your guaranty, you must provide an acceptable replacement in the form of a bond or other security.

**§ 585.529 Can I use a lease- or grant specific decommissioning account to meet**  **the financial assurance requirements related to decommissioning?** 

(a) In lieu of a surety bond, BOEM may authorize you to establish alease-, 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 http://www.treasurydirect.gov ).
(d) We may require you to commit a specified stream of revenues as payment

into the account so that the account will be fully funded, as prescribed in paragraph (a)(2) of this section. The commitment may include revenue from other operations.

Changes in Financial Assurance

**§ 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 When may BOEM cancel my**

**bond?**

When your lease or grant ends, your surety(ies) remain(s) responsible, and BOEM will retain any pledged security as shown in the following table:

Bond The period of liability ends . . . Your bond will not be released until . . .

(a) Bonds for commercial leases submitted

under § 585.515. When BOEM determines that you have met all of your obligations under the lease. Seven years after the lease ends, or a longerperiod 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. (b) Supplemental or decommissioning bonds

submitted under § 585.516. When BOEM determines that you have met all your decommissioning, site clearance, and other 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 . . . Your bond will not be released until . . .

(2) BOEM determines that the potential liability resulting from any undetected noncompliance is not greater than the amount

of the lease base bond. (c) Bonds submitted under §§ 585.520 and

585.521 for limited leases, ROW grants, or RUE grants. When BOEM determines that you have met all of your obligations under the limited lease or grant. 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 ofthe bond to meet any possible future obligations.

**§ 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.

**§ 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 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 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 S i 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

F i of the 27-percent aggregate revenue share due to all the eligible States according to the formula:

F i= (1/S i) ÷ (Si= 1* * *

n (1/S i)).

**§ 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


### 64756 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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.(b) conduct any activities pertaining to construction of facilities for commercial operations on your commercial lease, submit and obtain approval for your COP, according to §§ 585.620 through 585.629. (c) conduct any activities on your limited lease, ROW grant, or RUE

grant in any OCS area, submit and obtain approval for your GAP according to §§ 585.640 through 585.648.

**§ 585.601 When am I required to submit my plans to BOEM?** 

Your plan submission requirements depend on whether your lease or grant was issued competitively or noncompetitively under subpart B or subpart C of this part.

(a) If your lease or grant is issued competitively, you must submit your SAP or your GAP within 6 months of

issuance.

(b) If you request that a lease or grant be issued noncompetitively, you must submit your SAP or your GAP within 60 days after the Director issues a
determination that there is no competitive interest.

(c) If you intend to continue your commercial lease with an operations term, you must submit a COP, or a FERC license application, at least 6 months before the end of your site assessment

term.

(d) You may submit your COP or FERC license application with your

SAP.

(1) You must provide sufficient data and information with your COP for BOEM to complete the needed reviews and NEPA analysis; and

(2) BOEM may need to conduct additional reviews, including NEPA analysis, if significant new information becomes available after you complete your site assessment activities or you revise your COP. As a result of the additional reviews, we may require modification of your COP. **§ 585.602 What records must I maintain?** 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]**

Site Assessment Plan and Information Requirements for Commercial Leases

**§ 585.605 What is a Site Assessment Plan (SAP)?** 

(a) A SAP describes the activities ( e.g., installation of meteorological towers, meteorological buoys) you plan to perform for the characterization of your commercial lease, including your project easement, or to test technology
devices.

(1) Your SAP must describe how you will conduct your resource assessment ( e.g., meteorological and oceanographic data collection) or technology testing activities; and

(2) BOEM will withhold trade secrets
and commercial or financial information that is privileged or confidential from public disclosure under exemption 4 of the FOIA and as provided in § 585.113.

(b) Your SAP must include data from: (1) Physical characterization surveys ( e.g., geological and geophysical surveys or hazards surveys); and

(2) Baseline environmental surveys ( e.g., biological or archaeological surveys).

(c) You must receive BOEM approval of your SAP before you can begin any of the approved activities on your lease, as provided in § 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.

**§ 585.606 What must I demonstrate in my**

**SAP?**

(a) Your SAP must demonstrate that you have planned and are prepared to conduct the proposed site assessment
activities in a manner that conforms to your responsibilities listed in § 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 How do I submit my SAP?**

You must submit one paper copy and one electronic version of your SAP to BOEM at the address listed in § 585.110(a).

**§ 585.608 [Reserved]**

**§ 585.609 [Reserved]**

Contents of the Site Assessment Plan

**§ 585.610 What must I include in my SAP?**

Your SAP must include the following information, as applicable. (a) For all activities you propose to conduct under your SAP, you must provide the following information:

Project information Including

(1) Contact information ............................................................................. The name, address, e-mail address, and phone number of an authorized representative.(2) The site assessment or technology testing concept .......................... A discussion of the objectives; description of the proposed activities, including the technology you will use; and proposed schedule from start to completion. (3) Designation of operator, if applicable ................................................. As provided in § 585.405.(4) Commercial lease stipulations and compliance ................................. A description of the measures you took, or will take, to satisfy the conditions of any lease stipulations related to your proposed activities. (5) A location plat ..................................................................................... The surface location an d water depth for all proposed and existing structures, facilities, and appurtenances located both offshore and

onshore. (6) General structural and project design, fabrication, and installation ... Information for each type of facility associated with your project. (7) Deployment activities .......................................................................... A description of the safety, prevention, and environmental protection features or measures that you will use.(8) Your proposed measures for avoiding, minimizing, reducing, eliminating, and monitoring environmental impacts. A description of the measures you will use to avoid or minimize adverse effects and any potential incidental take, before you conductactivities on your lease, and how you will mitigate environmental impacts from your proposed activities, including a description of the measures you will use as required by subpart H of this part. (9) CVA nomination, if required ................................................................ CVA nominations for reports in subpart G of this part, as required by § 585.706, or a request to waive the CVA requirement, as required by § 585.705(c). (10) Reference information ....................................................................... A list of any document or published source that you cite as part of your plan. You may reference information and data discussed in other plans you previously submitted or that are otherwise readily available
to BOEM. (11) Decommissioning and site clearance procedures ............................ A discussion of methodologies. (12) Air quality information ....................................................................... Information as described in § 585.659 of this section. (13) A listing of all Federal, State, and local authorizations or approvals

required to conduct site assessment activities on your lease. A statement indicating whether such authorization or approval has been applied for or obtained.(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. Contact information and issues discussed.

(15) Financial assurance information ....................................................... Statements attesting that the activities and facilities proposed in yourSAP are or will be covered by an appropriate bond or other approved security, as required in §§ 585.515 and 585.516. (16) Other information .............................................................................. Additional information as requested by BOEM.

(b) You must provide the results of geophysical and geological surveys, hazards surveys, archaeological surveys (if required), and baseline collection studies ( e.g., biological) with the supporting data in your SAP:

Information Report contents Including

(1) Geotechnical ................... The results from the 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 underlyingconditions 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. A description of information sufficient to determine thepresence of the following features and their likely effects on your proposed facility, including:

(i) Shallow faults; (ii) Gas seeps or shallow gas; (ii) Slump blocks or slump sediments; (iv) Hydrates; and (v) Ice scour of seabed sediments.(3) Archaeological resources The results from the archaeological survey with supporting data, if required. (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. (4) Geological survey ........... The results from the geological survey with supporting

data. 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. (5) Biological survey ............ The results from the biological survey with supporting

data. A description of the results of a biological survey, including descriptions of the presence of live bottoms; hard bottoms; topographic features; and surveys ofother 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. (2) Water quality ....................................................................................... Turbidity and total suspended solids from construction. (3) Biological resources ............................................................................ Benthic communities, marine mammals, sea turtles, coastal and marine birds, fish and shellfish, plankton, seagrasses, and plant life. (4) Threatened or endangered species .................................................... As required by the Endangered Species Act (ESA) of 1973 (16 U.S.C.

1531 et seq. ). (5) Sensitive biological resources or habitats .......................................... 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. (6) Archaeological resources .................................................................... As required by the NHPA (16 U.S.C. 470 et seq. ), as amended. (7) Social and economic resources .......................................................... Employment, existing offshore and coastal infrastructure (including major sources of supplies, services, energy, and water), land use, subsistence resources and harvest practices, recreation, recreational and commercial fishing (including typical fishing seasons, location,and type), minority and lower income groups, coastal zone management programs, and viewshed. (8) Coastal and marine uses .................................................................... Military activities, vessel traffic, and energy and nonenergy mineral exploration or development.


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Type of information Including

(9) Consistency Certification .................................................................... As required by CZMA, as approp riate: (i) 15 CFR part 930, subpart D, for noncompetitive leases; (ii) 15 CFR part 930, subpart E, for competitive leases. (10) Other resources, conditions, and activities ....................................... 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 thoseidentified in the lease sale consistency determination, you may be subject to a new consistency review. In that case, BOEM will notify you of the determination and we will forward to the State CZM agency 1 copy and 1 electronic copy of your SAP, consistency certification, and necessary data and information required under 15 CFR part 930, subpart E, after BOEM has determined that all information requirements for the SAP are met and BOEM prepares its NEPA compliance document.(b) Noncompetitively ........................................... You will furnish a copy of your SAP, consistency certification, and necessary data and information pursuant to 15 CFR part 930, subpart D, to the State’s CZM agency and BOEM at

the same time.

**§ 585.613 How will BOEM process my**

**SAP?**

(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 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 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 What must I demonstrate in my**

**COP?**

Your COP must demonstrate that you have planned and are prepared to conduct the proposed activities in a manner that conforms to your responsibilities listed in § 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 thefollowing 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: Including:

(iv) Hydrates; or (v) Ice scour of seabed sediments.(2) Geological survey relevant to the design and siting of your facility. The results of the geological survey with supporting

data. 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. (3) Biological ........................ The results of the biological survey with supporting data A description of the results ofbiological surveys usedto determine the presence of live bottoms, hard bottoms, and topographic features, and surveys of other marine resources such as fish populations (including migratory populations), marine mammals, sea turtles,

and sea birds.(4) Geotechnical survey ....... The results of your sediment testing program with supporting data, the various field and laboratory test methods employed, and the applicability of thesemethods 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 designof 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. (i) The results of a testing program used to investigate the stratigraphic and engineering properties of thesediment 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 projectarea and within the project area as needed to determine the vertical and lateral variation in seabed conditions and to provide the relevant geotechnical data required for design. (5) Archaeological resources The results of the archaeological resource survey with supporting data. A description of the historic and prehistoric archaeological resources, as required by the NHPA (16

U.S.C. 470 et. seq. ), as amended. (6) Overall site investigation An overall site investigation report for your facility thatintegrates the findings of your shallow hazards surveys and geologic surveys, and, if required, your subsurface surveys with supporting data. 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. (2) Designation of operator, if applicable ................................................. As provided in § 585.405. (3) The construction and operation concept ............................................ A discussion of the objectives, descripti on of the proposed activities,tentative schedule from start to completion, and plans for phased development, as provided in § 585.629.(4) Commercial lease stipulations and compliance ................................. A description of the measures you took, or will take, to satisfy the conditions of any lease stipulations related to your proposed activities. (5) A location plat ..................................................................................... The surface location an d water depth for all proposed and existing structures, facilities, and appurtenances located both offshore and onshore, including all anchor/mooring data. (6) General structural and project design, fabrication, and installation ... Information for each type of structure associated wi th 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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Project information: Including:

(7) All cables and pipelines, including cables on project easements ...... Location, design and installation methods, testing, ma intenance, repair,safety devices, exterior corrosion protection, inspections, and decommissioning. (8) A description of the deployment activities .......................................... Safety, prevention, and environmental p rotection features or measures that you will use. (9) A list of solid and liquid wastes generated ......................................... Disposal methods and locations.(10) A listing of chemical products used (if stored volume exceeds Environmental Protection Agency (EPA) 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

that will be transferred each time. (11) A description of any vessels, vehicles, and aircraft you will use to

support your activities. An estimate of the frequency and duration of vessel/vehicle/aircraft traffic. (12) A general description of the operating procedures and systems ..... (i) Under normal conditions. (ii) In the case of accidents or emergencies, including those that are

natural or manmade. (13) Decommissioning and site clearance procedures ............................ A discussion of general concepts and methodologies. (14) A listing of all Federal, State, and local authorizations, approvals,

or permits that are required to conduct the proposed activities, including commercial operations. (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.(15) Your proposed measures for avoiding, minimizing, reducing, eliminating, and monitoring environmental impacts. A description of the measures you will use to avoid or minimize adverse effects and any potential incidental take before you conductactivities on your lease, and how you will mitigate environmental impacts from your proposed activities, including a description of the measures you will use as required by subpart H of this part. (16) Information you incorporate by reference ......................................... A listing of the documents you referenced

.(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. Contact information and issues discussed.

(18) Reference .......................................................................................... A list of any document or published source that you cite as part of your plan. You may reference information and data discussed in other plans you previously submitted or that are otherwise readily available
to BOEM. (19) Financial assurance .......................................................................... Statements attesting that the activities and facilities proposed in your COP are or will be covered by an appropriate bond or security, as required by §§ 585.515 and 585.516. (20) CVA nominations for reports required in subpart G of this part ...... 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).(21) Construction schedule ...................................................................... A reasonable schedule of construction activity showing significant milestones leading to the commencement of commercial operations. (22) Air quality information ....................................................................... As described in § 585.659 of this section. (23) Other information .............................................................................. Additional information as required by BOEM.

**§ 585.627 What information and certifications must I submit with my COP to**  **assist the BOEM in complying with NEPA**

**and other relevant laws?**

(a) You must submit with your COP
detailed information to assist BOEM in complying with NEPA and other

relevant laws. Your COP must describe those resources, conditions, and activities listed in the following table that could be affected by your proposed activities, or that could affect the activities proposed in your COP, including:

Type of information: Including:

(1) Hazard information .............................................................................. Meteorology, oceanography, sediment transport, geology, and shallow geological or manmade hazards. (2) Water quality ....................................................................................... Turbidity and total suspended solids from construction. (3) Biological resources ............................................................................ Benthic communities, marine mammals, sea turtles, coastal and marine birds, fish and shellfish, plankton, seagrasses, and plant life. (4) Threatened or endangered species .................................................... As defined by the ESA (16 U.S.C. 1531 et seq. ). (5) Sensitive biological resources or habitats .......................................... 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. (6) Archaeological resources .................................................................... As required by the NHPA (16 U.S.C. 470 et seq. ), as amended.


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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. (8) Coastal and marine uses .................................................................... Military activities, vessel traffic, and energy and nonenergy mineral exploration or development. (9) Consistency Certification .................................................................... As required by the CZMA: (i) 15 CFR part 930, subpart D, for noncompetitive leases. (ii) 15 CFR part 930, subpart E, for competitive leases. (10) Other resources, conditions, and activities ....................................... As identified by BOEM.

(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.

**§ 585.628 How will BOEM process my**

**COP?**

(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 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 May I develop my lease in phases?** 

In your COP, you may request development of your commercial lease in phases. In support of your request, you must provide details as to what portions of the lease will be initially developed for commercial operations and what portions of the lease will be reserved for subsequent phased development. **§ 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:

Document: Requirements are found in:

(1) Facility Design Report § 585.701(2) Fabrication and Installation Report .......... § 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.

**§ 585.634 What activities require a revision to my COP, and when will BOEM approve** 

**the revision?**

(a) You must notify BOEM in writing before conducting any activities not described in your approved COP, describing in detail the type of activities you propose to conduct. We will determine whether the activities you propose are authorized by your existing COP or require a revision to your COP. We may request additional information from you, if necessary, to make this
determination.

(b) BOEM will periodically review the activities conducted under an approved COP. The frequency and extent of the review will be based on the significance of any changes in available information,
and on onshore or offshore conditions affecting, or affected by, the activities conducted under your COP. If the
review indicates that the COP should be revised to meet the requirement of this part, we will require you to submit the
needed revisions.

(c) Activities for which a proposed revision to your COP will likely be necessary include:

(1) Activities not described in your approved COP;

(2) Modifications to the size or type of facility or equipment you will use;

(3) Change in the surface location of a facility or structure;

(4) Addition of a facility or structure not described in your approved COP;

(5) Change in the location of your onshore support base from one State to another or to a new base requiring expansion;

(6) Changes in the location of bottom disturbances (anchors, chains, etc. ) by 500 feet (152 meters) or greater from the approved locations ( e.g., if a specific anchor pattern was approved as a mitigation measure to avoid contact with bottom features, any change in the proposed bottom disturbances would likely trigger the need for a revision);

(7) Structural failure of one or more facilities; or

(8) Change in any other activity specified by BOEM.

(d) We may begin the appropriate NEPA analysis and relevant
consultations when we determine that a proposed revision could: (1) Result in a significant change in the impacts previously identified and evaluated;

(2) Require any additional Federal authorizations; or

(3) Involve activities not previously
identified and evaluated.

(e) When you propose a revision, we may approve the revision if we
determine that the revision is:

(1) Designed not to cause undue harm or damage to natural resources; life (including human and wildlife); property; the marine, coastal, or human
environment; or sites, structures, or objects of historical or archaeological significance; and

(2) Otherwise consistent with the provisions of subsection 8(p) of the OCS
Lands Act.

**§ 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 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 What is a General Activities Plan (GAP)?** 

(a) A GAP describes your proposed construction, activities, and conceptual decommissioning plans for all planned facilities, including testing of technology devices and onshore and support facilities that you will construct and use for your project, including any project easements for the assessment and development of your limited lease
or grant.

(b) You must receive BOEM approval of your GAP before you can begin any of the approved activities on your lease or grant. For a ROW grant or RUE grant issued competitively, you must submit your GAP within 6 months of issuance.

**§ 585.641 What must I demonstrate in my**
**GAP?**

Your GAP must demonstrate that you have planned and are prepared to conduct the proposed activities in a
manner that:

(a) Conforms to all applicable laws, implementing regulations, lease provisions and stipulations;

(b) Is safe; (c) Does not unreasonably interfere with other uses of the OCS, including those involved with National security or defense;

(d) Does not cause undue harm or damage to natural resources; life (including human and wildlife); property; the marine, coastal, or human
environment; or sites, structures, or objects of historical or archaeological significance;

(e) Uses best available and safest technology;

(f) Uses best management practices;
and

(g) Uses properly trained personnel.


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**§ 585.642 How do I submit my GAP?**

(a) You must submit one paper copy and one electronic version of your GAP
to BOEM at the address listed in § 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. **§ 585.643 [Reserved]**

**§ 585.644 [Reserved]**

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 surveys (if required), and baseline collection studies ( e.g., biological) with the supporting data in your GAP:

Information: Report contents: Including:

(1) Geotechnical ................... The results from the 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 underlyingconditions will not influence the integrity or performance of the structure. This could include a series of sampling locations (borings and in situ tests) as well as laboratory testing of soil samples, but may consist of a minimum of one deep boring with samples.(2) Shallow hazards ............. The results from the shallow hazards survey with supporting data. A description of information sufficient to determine thepresence of the following features and their likely effects on your proposed facility, including:

(i) Shallow faults; (ii) Gas seeps or shallow gas; (iii) Slump blocks or slump sediments; (iv) Hydrates; or (v) Ice scour of seabed sediments.(3) Archaeological resources The results from the archaeological survey with supporting data, if required. (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. (4) Geological survey ........... The results from the geological survey with supporting

data. 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. (5) Biological survey ............ The results from the biological survey with supporting

data. 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.(2) The site assessment or technology testing concept .......................... A discussion of the objectives; description of the proposed activities, including the technology you will use; and proposed schedule from start to completion. (3) Designation of operator, if applicable ................................................. As provided in § 585.405. (4) ROW, RUE or limited lease grant stipulations, if known .................... A description of the measures you took, or will take, to satisfy the conditions of any lease stipulations related to your proposed activities. (5) A location plat ..................................................................................... The surface location an d water depth for all proposed and existing structures, facilities, and appurtenances located both offshore and

onshore. (6) General structural and project design, fabrication, and installation ... Information for each type of facility associated with your project. (7) Deployment activities .......................................................................... A description of the safety, prevention, and environmental protection features or measures that you will use. (8) A list of solid and liquid wastes generated ......................................... Disposal methods and locations.


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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. (10) Reference information ....................................................................... A list of any document or published source that you cite as part of your plan. You may reference information and data discussed in other plans you previously submitted or that are otherwise readily available
to BOEM. (11) Decommissioning and site clearance procedures ............................ A discussion of methodologies. (12) Air quality information ....................................................................... As described in § 585.659 of this section. (13) A listing of all Federal, State, and local authorizations or approvals

required to conduct site assessment activities on your lease. A statement indicating whether such authorization or approval has been applied for or obtained.(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. Contact information and issues discussed.

(15) Financial assurance information ....................................................... Statements attesting that the activities and facilities proposed in yourGAP are or will be covered by an appropriate bond or other approved security, as required in §§ 585.520 and 585.521. (16) Other information .............................................................................. Additional information as requested by BOEM.

(c) If you are applying for a project easement or constructing a facility, or a combination of facilities deemed by BOEM to be complex or significant, you must provide the following information in addition to what is required in paragraphs (a) and (b) of this section and comply with the requirements of subpart G of this part:

Project information: Including:

(1) The construction and operation concept ............................................ A discussion of the objectives, descripti on of the proposed activities, and tentative schedule from start to completion. (2) All cables and pipelines, including cables on project easements ...... The location, design, installation methods, testing, m aintenance, repair,safety devices, exterior corrosion protection, inspections, and decommissioning. (3) A description of the deployment activities .......................................... Safety, prevention, and environmental p rotection features or measures that you will use. (4) A general description of the operating procedures and systems ....... (i) Under normal conditions. (ii) In the case of accidents or emergencies, including those that are

natural or manmade. (5) CVA nominations for reports required in subpart G of this part ........ 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).(6) Construction schedule ........................................................................ A reasonable schedule of construction activity showing significant milestones leading to the commencement of activities. (7) Other information ................................................................................ Additional information as required by the BOEM.

(d) BOEM will withhold trade secrets

and commercial or financial information that is privileged or confidential from public disclosure in accordance with the terms of § 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. (b) Water quality ....................................................................................... Turbidity and total suspended solids from construction. (c) Biological resources ............................................................................ Benthic communities, marine mammals, sea turtles, coastal and marine birds, fish and shellfish, plankton, seagrasses, and plant life. (d) Threatened or endangered species .................................................... As required by the ESA (16 U.S.C. 1531 et seq. ). (e) Sensitive biological resources or habitats .......................................... 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. (f) Archaeological resources ..................................................................... As required by NHPA (16 U.S.C. 470 et seq. ), as amended.


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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. (h) Coastal and marine uses .................................................................... Military activities, vessel traffic, and energy and nonenergy mineral exploration or development. (i) Consistency Certification ...................................................................... As required by CZMA: (1) 15 CFR part 930, subpart D, for noncompetitive leases; (2) 15 CFR part 930, subpart E, for competitive leases. (j) Other resources, conditions, and activities .......................................... As required by BOEM.

**§ 585.647 How will my GAP be processed for Federal consistency under the Coastal**  **Zone Management Act?**

Your GAP will be processed based on how your limited lease, ROW grant, or RUE grant was issued:

If your limited lease, ROW, or RUE grant was
issued: Your GAP will be processed as follows:

(a) Competitively, BOEM will forward one paper copy and one electronic copy of your GAP, consistency certification, and necessary data and information required under 15 CFR part 930, subpart E, after BOEM has determined that all information requirements for the GAP are met and BOEM prepares its NEPA compliance document. (b) Noncompetitively, You will furnish a copy of your GAP, consistency certification, and necessary data and information pursuant to 15 CFR part 930, subpart D, to the State’s CZM agency and BOEM at

the same time.

**§ 585.648 How will BOEM process my**

**GAP?**

(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 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.

**§ 585.649 [Reserved]**

Activities Under an Approved GAP

**§ 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.

**§ 585.651 When may I construct complex or significant OCS facilities on my limited**  **lease or any facilities on my project easement proposed under my GAP?** 

If you are applying for a project easement, or installing a facility or a combination of facilities on your limited lease deemed by BOEM to be complex or significant, as provided in § 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?** 

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.

**§ 585.653 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.


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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.

If your project is located . . . you must . . .

(1) in the Gulf of Mexico west of 87.5 ° west longitude (western Gulf of

Mexico). include in your plan any information required for BOEM to make the appropriate air quality determinations for your project. (2) anywhere else on the OCS ................................................................ follow the appropriate implementingregulations 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 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. You must submit 1 paper copy and 1 electronic copy.

(2) Location plat ................................................. (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. 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.

(3) Front, Side, and Plan View drawings ........... (i) Facility dimensions and orientation; (ii) Elevations relative to Mean Lower Low

Water; and (iii) Pile sizes and penetration. Your drawing sizes must not exceed 11 ′′ x 17′′. You must submit 1 paper copy and 1 electronic copy.

(4) Complete set of structural drawings ............. 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. Your drawing sizes must not exceed 11 ′′ x 17′′. You must submit 1 paper copy and 1 electronic copy.

(5) Summary of environmental data used for

design. A summary of the environmental data used inthe 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. 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). You must submit 1 paper copy and 1 electronic copy.

(7) A complete set of design calculations .......... Self-explanatory ............................................... You must subm it 1 paper copy and 1 electronic copy. (8) Project-specific studies used in the facility

design or installation. 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). You must submit 1 paper copy and 1 electronic copy.

(9) Description of the loads imposed on the facility. (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. You must submit 1 paper copy and 1 electronic copy.

(10) Geotechnical Report ................................... A list of all data from borings and recommended design parameters. You must submit 1 paper copy and 1 electronic copy.

(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 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. **§ 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. You must submit 1 paper copy and 1 electronic copy.

(2) Schedule ....................................................... Fabrication and installation .............................. Yo u must submit 1 paper copy and 1 electronic copy. (3) Fabrication information ................................. The industry standards you will use to ensurethe facilities are fabricated to the design criteria identified in your Facility Design Report. You must submit 1 paper copy and 1 electronic copy.

(4) Installation process information .................... Details associated with the deployment activities, equipment, and materials, includingonshore and offshore equipment and support, and anchoring and mooring patterns. You must submit 1 paper copy and 1 electronic copy.

(5) Federal, State, and local permits ( e.g., EPA,

Army Corps of Engineers). Either 1 copy of the permit or information on the status of the application. You must submit 1 paper copy and 1 electronic copy. (6) Environmental information ............................ (i) Water discharge; (ii) Waste disposal; (iii) Vessel information; and(iv) Onshore waste receiving treatment or disposal facilities. 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 asappropriate. 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.

**§ 585.703 What reports must I submit for project modifications and repairs?** 

(a) You must verify and, in a report to us, certify that major repairs and major modifications to the project conform to accepted engineering practices.

(1) A major repair is a corrective action involving structural members affecting the structural integrity of a portion of or all the facility.

(2) A major modification is an alteration involving structural members affecting the structural integrity of a portion of or all the facility.

(b) The report must also identify the location of all records pertaining to the major repairs or major modifications, as required in § 585.714(c).

(c) BOEM may require you to use a CVA for project modifications and repairs.

**§ 585.704 [Reserved]**

Certified Verification Agent

**§ 585.705 When must I use a Certified Verification Agent (CVA)?** 

You must use a CVA to review and certify the Facility Design Report, the Fabrication and Installation Report, and the Project Modifications and Repairs Report.

(a) You must use a CVA to:

(1) Ensure that your facilities are designed, fabricated, and installed in conformance with accepted engineering practices and the Facility Design Report and Fabrication and Installation Report;

(2) Ensure that repairs and major modifications are completed in conformance with accepted engineering practices; and

(3) Provide BOEM immediate reports of all incidents that affect the design, fabrication, and installation of the project and its components.

(b) BOEM may waive the requirement that you use a CVA if you can demonstrate the following:

If you demonstrate that . . . 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. The design of your structure(s).

(2) The manufacturer has successfully manufactured similar facilities,

and the facility will be fabricated in conformance with accepted engineering practices. The fabrication of your structure(s).

(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. The installation of your structure(s).

(4) Repairs and major modifications will be completed in conformance

with accepted engineering practices. The repair or major modification 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. **§ 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 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


### 64772 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations

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.

**§ 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; (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; (12) Alignment procedures; (13) Dimensional check of the overallstructure, 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.

**§ 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 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 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.

**§ 585.802 What must I do if I discover a potential archaeological resource while**  **conducting my approved activities?**

(a) If you, your subcontractors, or any agent acting on your behalf discovers a potential archaeological resource while conducting construction activities, or any other activity related to your project, you must:

(1) Immediately halt all 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.

**§ 585.803 How must I conduct my approved activities to protect essential fish** 

**habitats identified and described under the Magnuson-Stevens Fishery Conservation**  **and Management Act?**

(a) If, during the conduct of your approved activities, BOEM finds that
essential fish habitat or habitat areas of particular concern may be adversely affected by your activities, BOEM must
consult with National Marine Fisheries

Service.

(b) Any conservation recommendations adopted by BOEM to
avoid or minimize adverse affects on
Essential Fish Habitat will be incorporated as terms and conditions in the lease and must be adhered to by the applicant. BOEM may require additional surveys to define boundaries and
avoidance distances.

(c) If required, BOEM will specify the survey methods and instrumentations for conducting the biological survey and will specify the contents of the biological report.

**§§ 585.804–585.809 [Reserved]**

Safety Management Systems

**§ 585.810 What must I include in my Safety Management System?** 

You must submit a description of the Safety Management System you will use with your COP (provided under § 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. **§ 585.814 [Reserved]**

Equipment Failure and Adverse
Environmental Effects

**§ 585.815 What must I do if I have facility damage or an equipment failure?** 

(a) If you have facility damage or the failure of a pipeline, cable, or other equipment necessary for you to implement your approved plan, you must make repairs as soon as practicable. If you have a major repair, you must submit a report of the repairs to BOEM, as required in § 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.

**§ 585.822 What must I do when BOEM conducts an inspection?** 

(a) When BOEM conducts an inspection, you must:

(1) Provide access to all facilities on your lease (including your project easement) or grant; and

(2) Make the following available for BOEM to inspect:

(i) The area covered under a lease, ROW grant, or RUE grant;

(ii) All improvements, structures, and fixtures on these areas; and

(iii) All records of design, construction, operation, maintenance, repairs, or investigations on or related to
the area.

(b) You must retain these records in paragraph (a)(2)(iii) of this section until BOEM releases your financial assurance under § 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.

**§ 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.

**§ 585.824 How must I conduct self inspections?** 

(a) You must develop a comprehensive annual self-inspection plan covering all of your facilities. You must keep this plan wherever you keep your records and make it available to BOEM inspectors upon request. Your plan must specify:

(1) The type, extent, and frequency of in-place inspections that you will
conduct for both the above-water and
the below-water structures of all facilities and pertinent components of the mooring systems for any floating facilities; and

(2) How you are monitoring thecorrosion 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 (3) A summary of the inspection indicating what repairs, if any, were
needed and the overall structural condition of the facility.

**§ 585.825 When must I assess my**

**facilities?**

(a) You must perform an assessment of the structure, when needed, based on the platform assessment initiators listed
in sections 17.2.1–17.2.5 of API RP 2A– WSD, Recommended Practice for Planning, Designing and Constructing Fixed Offshore Platforms—Working Stress Design (as incorporated by reference in § 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.

**§§ 585.826–585.829 [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 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?** 

You accrue decommissioning obligations when you are or become a lessee or grant holder, and you eitherinstall, 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: (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. **§ 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.

**§ 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: (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. (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 Marine**  **Related 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.

**§ 585.1005 How do I request an Alternate**

**Use RUE?**

To request an Alternate Use RUE, you
must submit to BOEM all of the following:

(a) The name, address, e-mail address, and phone number of an authorized representative.

(b) A summary of the proposed activities for the use of an existing OCS facility, including:

(1) The type of activities that would involve the use of the existing OCS facility;

(2) A description of the existing OCS facility, including a map providing its location on the lease block;

(3) The names of the owner of the existing OCS facility, the operator, the lessee, and any owner of operating rights on the lease at which the facility is located;

(4) A description of additional structures or equipment that will be required to be located on or in the vicinity of the existing OCS facility in connection with the proposed activities;

(5) A statement indicating whether any of the proposed activities are intended to occur before existing activities on the OCS facility have ceased; and

(6) A statement describing how existing activities at the OCS facility will be affected if proposed activities are to occur at the same time as existing activities at the OCS facility.

(c) A statement affirming that the proposed activities sought to be approved under this subpart are not otherwise authorized by other provisions in this subchapter or any
other Federal law. (d) Evidence that you meet the requirements of § 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 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.

**§ 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 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. **§ 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 requirementswill 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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the prescribed time period, we will call for the forfeiture of your bond or other financial guarantee, and you will remain liable for all accidents or damages that might result from such failure.

**SUBCHAPTER C—APPEALS**

**PART 590—APPEAL PROCEDURES**

**Subpart A—Offshore Minerals Management Appeal Procedures** 

Sec. 590.1 What is the purpose of this subpart? 590.2 Who may appeal? 590.3 What is the time limit for filing an appeal? 590.4 How do I file an appeal? 590.5 Can I obtain an extension for filing my Notice of Appeal? 590.6 Are informal resolutions permitted? 590.7 Do I have to comply with the decision or order while my appeal is pending? 590.8 How do I exhaust my administrative

remedies?

**Subpart B—[Reserved]**

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

1331

**Subpart A—Offshore Minerals Management Appeal Procedures** 

**§ 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?**

If you are adversely affected by an
OMM official’s final decision or order issued under 30 CFR chapter V, subchapter C, you may appeal that
decision or order to the Interior Board of Land Appeals (IBLA). Your appeal must conform with the procedures found in this subpart and 43 CFR part 4, subpart E. A request for reconsideration of a BOEM decision concerning a lease bid, authorized in 30 CFR parts 556.47(e)(3), 581.21(a)(1), or 585.118(c), is not subject to the procedures found in this part.

**§ 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.

**§ 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).

**§ 590.6 Are informal resolutions permitted?** 

(a) You may seek informal resolution with the issuing officer’s next level supervisor during the 60-day period established in § 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.

**Subpart B—[Reserved]**

[FR Doc. 2011–22675 Filed 9–29–11; 12:00 pm]

**BILLING CODE 4310–MR–P**