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 and 

Standards 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 to 

the legal obligations or rights of nongovernmental entities, the Department 

further finds that good cause exists 

under 5 U.S.C. 553(d)(3) to make this 

rule effective on October 1, 2011, rather 

than a full 30 days after publication in 

the Federal Register. 

Proposed Rule 

BOEM and BSEE will also jointly 

issue a proposed rule that will address 

some more substantive changes to the 

regulations. In part, the proposed rule 

will address regulatory anomalies 

created by splitting the functions of one 

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Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations 64433 

agency into two bureaus. In certain 

cases, the split necessitated changing 

the wording of specific provisions. 

Rather than changing the wording in 

this final rule, we have concluded it is 

more appropriate to do so in a proposed 

rule. The proposed rule changes will be 

substantial enough in nature to 

necessitate public comments and 

publication of a Notice of Proposed 

Rulemaking (NPR). 

Reorganization of CFR Title 30 

Background Information 

This final rule assigns the regulations 

previously codified under Title 30 of the 

Code of Federal Regulations (30 CFR), 

chapter II—Minerals Management 

Service, Department of the Interior, 

Subchapter A—Minerals Revenue 

Management, Subchapter B—Offshore, 

and Subchapter C—Appeals; to BSEE, 

under chapter II and to BOEM, under 

chapter V. The assignment of the 

regulations is based on the 

responsibilities and authorities 

established by Secretarial Order No. 

3299, separating BSEE and BOEM and 

the January 19, 2011, statement that 

further clarified each bureau’s mission 

and functions. 

To effectively manage the energy and 

mineral resources of the Outer 

Continental Shelf (OCS), the current 

regulations must be separated based on 

the responsibilities of the new bureaus. 

Based on the responsibilities established 

by Secretarial Order No. 3299, 

separating BOEMRE into BOEM and 

BSEE, this direct final rule reorganizes 

the regulations previously found in 30 

CFR chapter II by: 

1. Retitling chapter II as ‘‘Bureau of 

Safety and Environmental 

Enforcement’’; 

2. Retaining the regulations that will 

be under the authority of BSEE in 

chapter II; 

3. Adding a new chapter, ‘‘Chapter 

V—Bureau of Ocean Energy 

Management’’; and 

4. Moving the regulations that will be 

under the authority of BOEM to 30 CFR 

chapter V. 

In addition to redesignating the 

regulations to the appropriate bureau, 

this rule makes minor supporting edits 

for clarification, consistency, or to 

reiterate current and longstanding 

practices. However, the regulatory 

requirements themselves are not 

changed. These edits generally fall 

under one of the following categories: 

• Updates to cross-references to 

reflect the two new sets of rules, such 

as: 

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, various 

provisions of this rule contain crossreferences to earlier approvals or other 

actions taken under redesignated 

sections. This rule replaces the crossreferences to previous sections with 

cross-references to new sections. 

Forms and Information Collection 

BOEM and BSEE will rename forms as 

either BOEM or BSEE forms; MMS will 

be removed from the form names. Each 

form will retain its already assigned 

number, except that all numbers will 

now be four digits. We will add a zero(s) 

in front of an existing form number 

where necessary (e.g., form MMS–123 

will now become form BSEE–0123). The 

forms themselves are not changed by 

this rule. 

There are no Information Collection 

(IC) burden changes in this rule. 

Assignment of Regulations and 

Explanations 

All sections that BSEE retains keep 

their existing numbers, reflecting their 

existing location in 30 CFR chapter II. 

BOEM citations are renumbered using 

the number ‘‘5’’ as the first number for 

the part, reflecting their new location in 

30 CFR chapter V. 

The following table (Table A) 

provides an overview of the assignment 

of regulations between BOEM and 

BSEE, by part. Many parts are retained 

in their entirety by BSEE or moved in 

their entirety to BOEM. Additional 

details of how other parts are divided 

between the two bureaus follow in 

Tables B through O. 

TABLE A—DERIVATION TABLE

Title 30—Mineral Resources 

Chapter II—Bureau of Ocean Energy Management, Regulation and Enforcement 

Current part New location Justification 

Subchapter A—Minerals Revenue Management 

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 Continental 

Shelf (OCS) receipts shared under the Gulf of Mexico Energy Security Act (GOMESA). ONRR will continue to distribute the revenue 

shares to Gulf producing States and Coastal Political Subdivisions. 

Subchapter B—Offshore 

Part 250—Oil and Gas and Sulphur 

Operations in the Outer Continental Shelf.

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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64434 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations 

TABLE A—DERIVATION TABLE—Continued 

Title 30—Mineral Resources 

Chapter II—Bureau of Ocean Energy Management, Regulation and Enforcement 

Current part New location Justification 

Part 251—Geological and Geophysical (G&G) Explorations of 

the Outer Continental Shelf.

Responsibilities divided between 

BOEM and BSEE.

BOEM will be responsible for issuing the permits and notices and 

overseeing the activities under the approved permit, as these are 

prelease, resource assessment-related activities. BSEE will be responsible for issuing permits for test drilling activities under their 

responsibilities for operations. Further details are provided in Table 

C. 

Part 252—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 both 

bureaus will collect, maintain, and use data and information collected under this program, both are responsible for managing the 

data and determining how and when the data and information are 

released. Further details are provided in Table D. 

Part 253—Oil Spill Financial 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 to 

the 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 Minerals 

Other Than Oil, Gas, and Sulphur.

Responsibilities divided between 

BOEM and BSEE.

Both BOEM and BSEE have responsibilities for operations conducted 

under a mineral lease for OCS minerals other than oil, gas, or sulphur. These responsibilities were divided between the two bureaus 

as detailed in Table M. 

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 under 

BOEM. At a later date, the renewable energy program will be reorganized and a determination will be made regarding what functions 

will be administered by which agency. 

Subchapter C—Appeals 

Part 290—Appeal Procedures ........ Both BOEM and 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 Gas 

Pipelines 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. 

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

The reorganization of the individual 

parts and subparts is as follows: 

Subchapter A—Minerals Revenue 

Management 

Part 203—Relief or Reduction in Royalty 

Rates—Retained in Its Entirety in BSEE, 

Chapter II 

BSEE is responsible for the regulatory 

oversight of need-based royalty relief 

awarded after lease issuance and the 

tracking of all royalty-free production. 

Part 219—Distribution and 

Disbursement of Royalties, Rentals, and 

Bonuses—Moved in Its Entirety to 

BOEM, Chapter V, Part 519 

BOEM will perform revenue share 

calculations for OCS receipts shared 

under GOMESA. 

Subchapter B—Offshore 

Part 250—Oil and Gas and Sulphur 

Operations in the Outer Continental 

Shelf 

Part 250 established the requirements 

for offshore oil, natural gas, and sulphur 

operations. These operations include 

activities after the lease is established. 

Most of current Part 250 will stay under 

BSEE, with some sections going to 

BOEM. The details of this division are 

as follows. 

TABLE B—DETAILED TABLE FOR PART 250 

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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64436 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations 

TABLE B—DETAILED TABLE FOR PART 250—Continued 

Current citation and BSEE citation 

(if applicable) 

Implementing bureau and BOEM 

citation (if applicable) Explanation 

§ 250.119 Will MMS approve subsurface gas storage? 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 and 

operations 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 fulfilling 

leasehold 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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TABLE B—DETAILED TABLE FOR PART 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 be 

met 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 when 

am 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 lease 

term, 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. Past 

the 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 lease 

term, 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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64438 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations 

TABLE B—DETAILED TABLE FOR PART 250—Continued 

Current citation and BSEE citation 

(if applicable) 

Implementing bureau and BOEM 

citation (if applicable) Explanation 

§ 250.186 What reporting information and report forms must I submit? 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 information 

collected will be made available to the public and what data and information will be made available for limited inspection. The section 

was divided based on the type of data and information addressed 

in each paragraph. 

BSEE—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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Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations 64439 

TABLE B—DETAILED TABLE FOR PART 250—Continued 

Current citation and BSEE citation 

(if applicable) 

Implementing bureau and BOEM 

citation (if applicable) Explanation 

§ 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 operations 

on 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 

(H2S) 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, what 

planning 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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64440 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations 

TABLE B—DETAILED TABLE FOR PART 250—Continued 

Current citation and BSEE citation 

(if applicable) 

Implementing bureau and BOEM 

citation (if applicable) Explanation 

§ 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 

(H2S) 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, what 

planning 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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Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations 64441 

TABLE B—DETAILED TABLE FOR PART 250—Continued 

Current citation and BSEE citation 

(if applicable) 

Implementing bureau and BOEM 

citation (if applicable) Explanation 

§ 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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64442 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations 

TABLE B—DETAILED TABLE FOR PART 250—Continued 

Current citation and BSEE citation 

(if applicable) 

Implementing bureau and BOEM 

citation (if applicable) Explanation 

§ 250.287 For what development 

projects must I submit a DWOP? 

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 of 

the 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 to 

manage 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 to 

manage 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 to 

manage 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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Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations 64443 

TABLE B—DETAILED TABLE FOR PART 250—Continued 

Current citation and BSEE citation 

(if applicable) 

Implementing bureau and BOEM 

citation (if applicable) Explanation 

Subpart J—Pipelines and Pipeline Rights-of-Way 

Mostly retained by BSEE, except for provisions related to bond requirements (§ 250.1011). Bonding for all activities is the responsibility of 

BOEM, and the bonding section will be moved to § 550.1011. The rest of pipeline operations, including the issuance of pipeline rights-of-way, 

are under the authority of BSEE. 

§ 250.1000 General requirements. Retained by BSEE ......................... 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 responsibilities. 

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64444 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations 

TABLE B—DETAILED TABLE FOR PART 250—Continued 

Current citation and BSEE citation 

(if applicable) 

Implementing bureau and BOEM 

citation (if applicable) Explanation 

§ 250.1150 What are the general 

reservoir production requirements? 

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 H2S? 

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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Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations 64445 

TABLE B—DETAILED TABLE FOR PART 250—Continued 

Current citation and BSEE citation 

(if applicable) 

Implementing bureau and BOEM 

citation (if applicable) Explanation 

Subpart N—Outer Continental Shelf (OCS) Civil Penalties 

Retained in both bureaus in its entirety, with the exception of provisions in current § 250.1460 that are specific to operational violations penalized only by BSEE. BOEM issues civil penalties for violations that occur prior to commencement of lease operations and not involving safety 

and environmental matters, but arising from the lease management functions and regulations of BOEM. BSEE issues civil penalties for violations that occur after permits are approved; these violations would include violations of lease terms or approved plans that occur during operations. 

Subpart O—Well Control and Production Safety Training 

Retained in its entirety by BSEE. This subpart establishes training requirements for individuals working in the offshore oil and gas industry; 

which is the responsibility of BSEE, under its authority for regulatory enforcement of safety related to offshore operations. 

Subpart P—Sulphur Operations 

Retained in its entirety by BSEE. Sulphur operations are the responsibility of BSEE, under the authority for regulatory enforcement of safety, environment and conservation compliance of the Nation’s offshore resources. 

Subpart Q—Decommissioning Activities 

Retained in its entirety by BSEE. Decommissioning activities are the responsibility of BSEE, under the authority for regulatory enforcement of 

safety, environment and conservation compliance of the Nation’s offshore resources. 

Subpart R—[Reserved] 

Subpart S—Safety and Environmental Management Systems (SEMS) 

Retained in its entirety by BSEE. This subpart addresses operator developed SEMS programs; these programs are the responsibility of BSEE, 

under the authority for regulatory enforcement of safety, environment and conservation compliance of the Nation’s offshore resources. 

Part 251—Geological and Geophysical 

(G&G) Explorations of the Outer 

Continental Shelf 

This part establishes requirements to 

conduct G&G activities related to oil, 

gas, and sulphur on unleased lands, or 

lands under lease to a third party. Most 

of this part will be the responsibility of 

BOEM, under its authority to conduct 

exploration or scientific research 

activities. Some sections that address 

drilling will go to BSEE that address 

drilling. 

TABLE C—DETAILED TABLE FOR PART 251 

Current citation and BSEE citation 

(if applicable) 

Implementing bureau and BOEM 

citation (if applicable) Explanation 

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

§ 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 activities 

are under the authority of BOEM. 

§ 251.11 Submission, inspection, 

and selection of geological data 

and information collected under a 

permit 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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64446 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations 

TABLE C—DETAILED TABLE FOR PART 251—Continued 

Current citation and BSEE citation 

(if applicable) 

Implementing bureau and BOEM 

citation (if applicable) Explanation 

§ 251.12 Submission, inspection, 

and selection of geophysical data 

and information collected under a 

permit and processed by permittees or third parties.

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 the 

required information from lessees and operators who conduct business on the OCS. Information collection is required in this part for 

aspects regulated by both BSEE and BOEM. 

Part 252—Outer Continental Shelf 

(OCS) Oil and Gas Information Program 

Both BOEM and BSEE will have this 

part in its entirety. Both bureaus will be 

responsible for collecting and 

maintaining certain data and 

information. This subpart establishes 

the responsibilities of the bureau for 

protecting and releasing this data. 

TABLE D—DETAILED TABLE FOR PART 252 

Current citation and BSEE citation 

(if applicable) 

Implementing bureau and BOEM 

citation (if applicable) Explanation 

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

§ 252.1 Purpose ............................ In both BSEE and BOEM § 552.1 Both BSEE and BOEM will collect, maintain, and use data collected 

under this program. Both bureaus are responsible for managing the 

data and determining how and when the data is released. 

§ 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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TABLE E—DETAILED TABLE FOR PART 253 

Current citation and BSEE citation 

(if applicable) 

Implementing bureau and BOEM 

citation (if applicable) Explanation 

Subpart A—General 

§ 253.1 What is the purpose of 

this part? 

Moved to BOEM, § 553.1 .............. 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 to 

verify 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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TABLE E—DETAILED TABLE FOR PART 253—Continued 

Current citation and BSEE citation 

(if applicable) 

Implementing bureau and BOEM 

citation (if applicable) Explanation 

§ 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 to 

my 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. 

TABLE F—DETAILED TABLE FOR PART 254 

Current citation and BSEE citation 

(if applicable) 

Implementing bureau and BOEM 

citation (if applicable) Explanation 

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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TABLE F—DETAILED TABLE FOR PART 254—Continued 

Current citation and BSEE citation 

(if applicable) 

Implementing bureau and BOEM 

citation (if applicable) Explanation 

§ 254.8 May I appeal decisions 

under this part? 

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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64450 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations 

TABLE F—DETAILED TABLE FOR PART 254—Continued 

Current citation and BSEE citation 

(if applicable) 

Implementing bureau and BOEM 

citation (if applicable) Explanation 

§ 254.53 Submitting a response 

plan developed under State requirements.

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. 

TABLE G—DETAILED TABLE FOR PART 256 

Current citation and BSEE citation 

(if applicable) 

Implementing bureau and BOEM 

citation (if applicable) Explanation 

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

§ 256.0 Authority for information 

collection.

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-way 

grant 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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TABLE G—DETAILED TABLE FOR PART 256—Continued 

Current citation and BSEE citation 

(if applicable) 

Implementing bureau and BOEM 

citation (if applicable) Explanation 

Subpart E—Area Identification and Tract Size 

§ 256.26 General .......................... Moved to BOEM, § 556.26 ............ 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 under 

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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TABLE G—DETAILED TABLE FOR PART 256—Continued 

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 lease 

term, 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 initiate 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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TABLE H—DETAILED TABLE FOR PART 259 

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. 

TABLE I—DETAILED TABLE FOR PART 260 

Current citation and BSEE citation 

(if applicable) 

Implementing bureau and BOEM 

citation (if applicable) Explanation 

Subpart A—General Provisions 

§ 260.1 What is the purpose of 

this part? 

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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TABLE I—DETAILED TABLE FOR PART 260—Continued 

Current citation and BSEE citation 

(if applicable) 

Implementing bureau and BOEM 

citation (if applicable) Explanation 

§ 260.124 How will royalty suspension apply if MMS assigns a 

lease issued in a sale held after 

November 2000 to a field that 

has a pre-Act lease? 

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. 

TABLE J—DETAILED TABLE FOR PART 270 

Current citation and BSEE citation 

(if applicable) 

Implementing bureau and BOEM 

citation (if applicable) Explanation 

§ 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. 

TABLE K—DETAILED TABLE FOR PART 280 

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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TABLE K—DETAILED TABLE FOR PART 280—Continued 

Current citation and BSEE citation 

(if applicable) 

Implementing bureau and BOEM 

citation (if applicable) Explanation 

§ 280.3 What requirements must I 

follow when I conduct 

prospecting or research activities? 

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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TABLE K—DETAILED TABLE FOR PART 280—Continued 

Current citation and BSEE citation 

(if applicable) 

Implementing bureau and BOEM 

citation (if applicable) Explanation 

§ 280.50 When do I notify MMS 

that geophysical data and information are available for submission, inspection, and selection? 

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. 

TABLE L—DETAILED TABLE FOR PART 281 

Current citation and BSEE citation 

(if applicable) 

Implementing bureau and BOEM 

citation (if applicable) Explanation 

Subpart A—General 

§ 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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Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations 64457 

TABLE L—DETAILED TABLE FOR PART 281—Continued 

Current citation and BSEE citation 

(if applicable) 

Implementing bureau and BOEM 

citation (if applicable) Explanation 

§ 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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64458 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations 

Part 282—Operations in the Outer 

Continental Shelf for Minerals Other 

Than Oil, Gas, and Sulphur 

Both BOEM and BSEE have 

responsibilities for operations 

conducted under a mineral lease for 

OCS minerals other than oil, gas, or 

sulphur. 

As stated previously, ONRR has the 

authority to determine the value for 

royalty purposes of minerals and other 

products produced on the OCS under 

Secretarial Order No. 3299. Because 

ONRR is the office responsible for 

valuation, technical corrections were 

made to this part to reflect that 

authority. This rule does not change the 

valuation authority possessed by ONRR 

or the procedures by which that 

authority is implemented. It merely 

revises the references in the regulations 

to conform to those in current 

Secretarial delegations. It has no effect 

on the rights, obligations, or interests of 

affected parties. It affects solely the 

organization, procedure, and practice of 

the agencies. 

These responsibilities were divided 

between the bureaus as follows: 

TABLE M—DETAILED TABLE FOR PART 282 

Current citation and BSEE citation 

(if applicable) 

Implementing bureau and BOEM 

citation (if applicable) Explanation 

Subpart A—General 

§ 282.0 Authority for information 

collection.

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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Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations 64459 

TABLE M—DETAILED TABLE FOR PART 282—Continued 

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 

TABLE N—DETAILED TABLE FOR PART 290 

Current citation and BSEE citation 

(if applicable) 

Implementing bureau and BOEM 

citation (if applicable) Explanation 

Subpart A—Offshore Minerals Management Appeal Procedures 

§ 290.1 What is the purpose of 

this subpart? 

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 

TABLE O—DETAILED TABLE FOR PART 291 

Current citation and BSEE citation 

(if applicable) 

Implementing bureau and BOEM 

citation (if applicable) Justification 

SUBCHAPTER C—APPEALS 

§ 291.1 What is MMS’s authority 

to collect information? 

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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64460 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations 

TABLE O—DETAILED TABLE FOR PART 291—Continued 

Current citation and BSEE citation 

(if applicable) 

Implementing bureau and BOEM 

citation (if applicable) Justification 

§ 291.100 What is the purpose of 

this part? 

Retained in its entirety in BSEE, 

chapter II.

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 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 and 

gas 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 and 

gas 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 and 

gas pipelines under OCSLA. Offshore operations are under the authority of BSEE. 

§ 291.105 What must a complaint 

contain? 

Retained in its entirety in BSEE, 

chapter II.

This section addresses open and nondiscriminatory access to oil and 

gas 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 and 

gas 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 and 

gas 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 and 

gas 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 and 

gas 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 and 

gas 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 and 

gas 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 transporter 

has provided open and nondiscriminatory access? 

Retained in its entirety in BSEE, 

chapter II.

This section addresses open and nondiscriminatory access to oil and 

gas pipelines under OCSLA. Offshore operations are under the authority of BSEE. 

§ 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 and 

gas 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 and 

gas 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 and 

gas pipelines under OCSLA. Offshore operations are under the authority of BSEE. 

Procedural Matters 

Regulatory Planning and Review 

(Executive Order (E.O.) 12866) 

This direct final rule is not a 

significant rule as determined by the 

Office of Management and Budget 

(OMB) and is not subject to review 

under E.O. 12866. This direct final rule 

reorganizes the title 30 CFR chapter II 

regulations; this rule does not change 

existing regulatory requirements. 

(1) This direct final rule will not have 

an annual effect of $100 million or more 

on the economy. It will not adversely 

affect in a material way the economy, 

productivity, competition: jobs; the 

environment; public health or safety; or 

state, local, or Tribal governments or 

communities. 

(2) This direct final rule will not 

create a serious inconsistency or 

otherwise interfere with an action taken 

or planned by another agency. 

(3) This direct final rule will not alter 

the budgetary effects of entitlements, 

grants, user fees, or loan programs or the 

rights or obligations of their recipients. 

(4) This direct final rule will not raise 

novel legal or policy issues arising out 

of legal mandates, the President’s 

priorities, or the principles set forth in 

E.O. 12866. 

Regulatory Flexibility Act 

This direct final rule is exempt from 

the notice and comment provisions of 

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Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations 64461 

the Administrative Procedure Act 

(APA), 5 U.S.C. 553; therefore, the 

requirements of the Regulatory 

Flexibility Act do not apply, 5 U.S.C. 

603(a). 

Small Business Regulatory Enforcement 

Fairness Act 

This direct final rule is not a major 

rule under the Small Business 

Regulatory Enforcement Fairness Act (5 

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

a. Will not have an annual effect on 

the economy of $100 million or more. 

b. Will not cause a major increase in 

costs or prices for consumers; 

individual industries; Federal, state, or 

local government agencies; or 

geographic regions. 

c. Will not have significant adverse 

effects on competition, employment, 

investment, productivity, innovation, or 

the ability of U.S.-based enterprises to 

compete with foreign-based enterprises. 

The requirements apply to all entities 

operating on the OCS. This direct final 

rule reorganizes the title 30 CFR chapter 

II regulations and does not change 

existing regulatory requirements. 

Unfunded Mandates Reform Act of 1995 

This direct final rule will not impose 

an unfunded mandate on state, local, or 

Tribal governments, or the private sector 

of more than $100 million per year. This 

direct final rule will not have a 

significant or unique effect on state, 

local, or Tribal governments, or the 

private sector. A statement containing 

the information required by the 

Unfunded Mandates Reform Act (2 

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

Takings Implication Assessment (E.O. 

12630) 

Under the criteria in E.O. 12630, this 

direct final rule does not have 

significant takings implications. This 

direct final rule is not a governmental 

action capable of interference with 

constitutionally protected property 

rights. A Takings Implication 

Assessment is not required. 

Federalism (E.O. 13132) 

Under the criteria in E.O. 13132, this 

direct final rule does not have 

federalism implications. This direct 

final rule will not substantially and 

directly affect the relationship between 

the Federal and State governments. To 

the extent that State and local 

governments have a role in OCS 

activities, this direct final rule will not 

affect that role. A Federalism 

Assessment is not required. 

Civil Justice Reform (E.O. 12988) 

This direct final rule complies with 

the requirements of E.O. 12988. 

Specifically, this rule: 

(a) Meets the criteria of section 3(a) 

requiring that all regulations be 

reviewed to eliminate errors and 

ambiguity and be written to minimize 

litigation; and 

(b) Meets the criteria of section 3(b)(2) 

requiring that all regulations be written 

in clear language and contain clear legal 

standards. 

Consultation With Indian Tribes (E.O. 

13175) 

Under the criteria in E.O. 13175, we 

have evaluated this direct final rule and 

determined that it has no substantial 

effects on federally recognized Indian 

Tribes. 

Paperwork Reduction Act (PRA) of 1995 

This final rule does not contain new 

information collection requirements, 

and a submission to OMB is not 

required under 44 U.S.C. 3501 et seq. 

All information collections referred to 

in this rulemaking are in the 1010 

numbering series and are unchanged. 

National Environmental Policy Act of 

1969 

This rule does not constitute a major 

Federal action significantly affecting the 

quality of the human environment. We 

evaluated this rule under the criteria of 

the National Environmental Policy Act, 

43 CFR Part 46 and 516 Departmental 

Manual 15. This rule meets the criteria 

set forth in 43 CFR 46.210(i) in that this 

proposed rule is ‘‘* * * of an 

administrative, financial, legal, 

technical, or procedural nature * * *.’’ 

This rule also meets the criteria set forth 

in 516 Departmental Manual 15.4(C)(1) 

for a ‘‘Categorical Exclusion’’ in that its 

impacts are limited to administrative, 

economic or technological effects. 

Further, we have evaluated this 

proposed rule to determine if it involves 

any of the extraordinary circumstances 

that would require an environmental 

assessment or an environmental impact 

statement as set forth in 43 CFR 46.215. 

We concluded that this rule does not 

meet any of the criteria for extraordinary 

circumstances as set forth therein. 

Data Quality Act 

In developing this rule, we did not 

conduct or use a study, experiment, or 

survey requiring peer review under the 

Data Quality Act (Pub. L. 106–554, app. 

C section 515, 114 Stat. 2763, 2763A– 

153–154). 

Effects of the Nation’s Energy Supply 

(E.O. 13211) 

This direct final rule is not a 

significant energy action under the 

definition in E.O. 13211. A Statement of 

Energy Effects is not required. 

List of Subjects 

30 CFR Part 203 

Continental shelf, Government 

contracts, Indians—lands, Mineral 

royalties, Oil and gas exploration, 

Public lands—mineral resources, 

Sulphur. 

30 CFR Part 250 

Administrative practice and 

procedure, Continental shelf, Oil and 

gas exploration, Public lands—mineral 

resources, Reporting and recordkeeping 

requirements. 

30 CFR Part 251 

Continental shelf, Freedom of 

information, Oil and gas exploration, 

Public lands—mineral resources, 

Reporting and recordkeeping 

requirements, Research. 

30 CFR Part 252 

Continental shelf, Freedom of 

information, Intergovernmental 

relations, Oil and gas exploration, 

Public lands—mineral resources, 

Reporting and recordkeeping 

requirements. 

30 CFR Part 254 

Continental shelf, Intergovernmental 

relations, Oil and gas exploration, Oil 

pollution, Pipelines, Public lands— 

mineral resources, Reporting and 

recordkeeping requirements. 

30 CFR Part 256 

Administrative practice and 

procedure, Continental shelf, 

Environmental protection, Government 

contracts, Intergovernmental relations, 

Oil and gas exploration, Public lands— 

mineral resources, Public lands—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 a 

qualified deep well or a qualified ultradeep well. 

Redetermination means our 

reconsideration of our determination on 

royalty relief because you request it 

after: 

(1) We have rejected your application; 

(2) We have granted relief but you 

want a larger suspension volume; 

(3) We withdraw approval; or 

(4) You renounce royalty relief. 

Renounce means action you take to 

give up relief after we have granted it 

and before you start production. 

Reservoir means an underground 

accumulation of oil or natural gas, or 

both, characterized by a single pressure 

system and segregated from other such 

accumulations. 

Royalty suspension (RS) lease means 

a lease that: 

(1) Is issued as part of an OCS lease 

sale held after November 28, 2000; 

(2) Is in locations or planning areas 

specified in a particular Notice of OCS 

Lease Sale offering that lease; and 

(3) Is offered subject to a royalty 

suspension specified in a Notice of OCS 

Lease Sale published in the Federal 

Register. 

Royalty suspension supplement (RSS) 

means a royalty suspension volume 

resulting from drilling a certified 

unsuccessful well that is applied to 

future natural gas and oil production 

generated at any drilling depth on, or 

allocated under a BSEE-approved unit 

agreement to, the same lease. 

Royalty suspension volume (RSV) 

means a volume of production from a 

lease that is not subject to royalty under 

the provisions of this part. 

Sidetrack means, for the purpose of 

this subpart, a well resulting from 

drilling an additional hole to a new 

objective bottom-hole location by 

leaving a previously drilled hole. A 

sidetrack also includes drilling a well 

from a platform slot reclaimed from a 

previously drilled well or re-entering 

and deepening a previously drilled well. 

A bypass from a sidetrack (e.g., drilling 

around material blocking the hole, or to 

straighten crooked holes) is part of the 

sidetrack. 

Sidetrack measured depth means the 

actual distance or length in feet a 

sidetrack is drilled beginning where it 

exits a previously drilled hole to the 

bottom hole of the sidetrack, that is, to 

its total depth. 

Sunk costs for an authorized field 

means the after-tax eligible costs that 

you (not third parties) incur for 

exploration, development, and 

production from the spud date of the 

first discovery on the field to the date 

we receive your complete application 

for royalty relief. The discovery well 

must be qualified as producible under 

30 CFR part 550, subpart A. Sunk costs 

include the rig mobilization and 

material costs for the discovery well that 

you incurred before its spud date. 

Sunk costs for an expansion or 

development project means the after-tax 

eligible costs that you (not third parties) 

incur for only the first well that 

encounters hydrocarbons in the 

reservoir(s) included in the application 

and that meets the producibility 

requirements under 30 CFR part 550, 

subpart A on each lease participating in 

the application. Sunk costs include rig 

mobilization and material costs for the 

discovery wells that you incurred before 

their spud dates. 

Ultra-deep well means either an 

original well or a sidetrack completed 

with a perforated interval the top of 

which is at least 20,000 feet TVD SS. An 

ultra-deep well subsequently reperforated less than 20,000 feet TVD SS 

in the same reservoir is still an ultradeep well. 

Withdraw means action we take on a 

field that has qualified for relief if you 

have not met one or more of the 

performance conditions. 

§ 203.1 What is BSEE’s authority to grant 

royalty relief? 

The Outer Continental Shelf (OCS) 

Lands Act, 43 U.S.C. 1337, as amended 

by the OCS Deep Water Royalty Relief 

Act (DWRRA), Public Law 104–58 and 

the Energy Policy Act of 2005, Public 

Law 109–058 authorizes us to grant 

royalty relief in four situations. 

(a) Under 43 U.S.C. 1337(a)(3)(A), we 

may reduce or eliminate any royalty or 

a net profit share specified for an OCS 

lease to promote increased production. 

(b) Under 43 U.S.C. 1337(a)(3)(B), we 

may reduce, modify, or eliminate any 

royalty or net profit share to promote 

development, increase production, or 

encourage production of marginal 

resources on certain leases or categories 

of leases. This authority is restricted to 

leases in the GOM that are west of 87 

degrees, 30 minutes West longitude, and 

in the planning areas offshore Alaska. 

(c) Under 43 U.S.C. 1337(a)(3)(C), we 

may suspend royalties for designated 

volumes of new production from any 

lease if: 

(1) Your lease is in deep water (water 

at least 200 meters deep); 

(2) Your lease is in designated areas 

of the GOM (west of 87 degrees, 30 

minutes West longitude); 

(3) Your lease was acquired in a lease 

sale held before the DWRRA (before 

November 28, 1995); 

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(4) We find that your new production 

would not be economic without royalty 

relief; and 

(5) Your lease is on a field that did not 

produce before enactment of the 

DWRRA, or if you propose a project to 

significantly expand production under a 

Development Operations Coordination 

Document (DOCD) or a supplementary 

DOCD, that the Bureau of Ocean Energy 

Management (BOEM) approved after 

November 28, 1995. 

(d) Under 42 U.S.C. 15904–15905, we 

may suspend royalties for designated 

volumes of gas production from deep 

and ultra-deep wells on a lease if: 

(1) Your lease is in shallow water 

(water less than 400 meters deep) and 

you produce from an ultra-deep well 

(top of the perforated interval is at least 

20,000 feet TVD SS) or your lease is in 

waters entirely more than 200 meters 

and entirely less than 400 meters deep 

and you produce from a deep well (top 

of the perforated interval is at least 

15,000 feet TVD SS); 

(2) Your lease is in the designated 

area of the GOM (wholly west of 87 

degrees, 30 minutes west longitude); 

and 

(3) Your lease is not eligible for deep 

water royalty relief. 

§ 203.2 How can I obtain royalty relief? 

We may reduce or suspend royalties 

for Outer Continental Shelf (OCS) leases 

or projects that meet the criteria in the 

following table. 

If you have a lease . . . And if you . . . Then we may grant you . . . 

(a) With earnings that cannot sustain production (i.e., End-of-life lease), Would abandon otherwise potentially recoverable resources but seek to increase production by operating beyond the point at which 

the lease is economic under the existing 

royalty rate, 

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, or 

form 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 and 

ultra-deep wells, a smaller royalty suspension for a volume of gas or oil produced by 

all wells on your lease (see §§ 203.40 

through 203.49). 

(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, 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, 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 approval 

provisions for the discretionary end-oflife and deep water royalty relief 

programs in §§ 203.50 to 203.91. 

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Because royalty relief for deep gas on 

leases not subject to deep water royalty 

relief, as provided for under §§ 203.40 to 

203.48, does not involve an application, 

its provisions do not parallel the other 

two royalty relief programs and are not 

summarized in this section. 

(a) We require the information 

elements indicated by an X in the 

following table and described in 

§§ 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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64468 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations 

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 production 

from qualified phase 2 or phase 3 ultradeep wells that: 

(1) Occurs before December 18, 2008, 

and 

(2) Is subject to application of an RSV 

under either § 203.31 or § 203.41. 

(d) The following examples illustrate 

how this section applies. These 

examples assume that your lease is 

located in the GOM west of 87 degrees, 

30 minutes West longitude and in water 

less than 400 meters deep (see 

§ 203.30(a)), has no existing deep or 

ultra-deep wells and that the price 

thresholds prescribed in § 203.36 have 

not been exceeded. 

Example 1: In 2008, you drill and begin 

producing from an ultra-deep well with a 

perforated interval the top of which is 25,000 

feet TVD SS, and your lease has had no prior 

production from a deep or ultra-deep well. 

Assuming your lease has no deepwater 

royalty relief (see § 203.30(c)), your lease is 

eligible (according to § 203.30(b)) to earn an 

RSV under § 203.31 because it has not yet 

produced from a deep well. Your lease earns 

an RSV of 35 BCF under this section when 

this well begins producing. According to 

§ 203.31(a), your 25,000 foot well qualifies 

your lease for this RSV because the well was 

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 the 

qualified deep well and the qualified ultradeep well would share your lease’s total RSV 

of 15 BCF in the manner prescribed in 

§§ 203.33 and 203.43. 

Example 6: In 2008, you spud a qualified 

ultra-deep well that is a sidetrack with a 

sidetrack measured depth of 21,000 feet and 

a perforated interval the top of which is 

25,000 feet TVD SS. This well meets the 

definition of an ultra-deep well but is too 

long to be classified an ultra-deep short 

sidetrack in § 203.0. If your lease is located 

in 150 meters of water and has not previously 

produced from a deep well, your lease earns 

an RSV of 35 BCF because it was drilled after 

the effective date for earning this RSV. 

Further, this RSV applies to gas production 

from this and any future qualified deep and 

qualified ultra-deep wells on your lease, as 

prescribed in § 203.33. The absence of an 

expiration date for earning an RSV on an 

ultra-deep well means this long sidetrack 

well becomes a qualified well whenever it 

starts production. If your sidetrack has a 

sidetrack measured depth of 14,000 feet and 

begins production in March 2009, it earns an 

RSV of 12.4 BCF under this section because 

it meets the definitions of a phase 2 ultradeep well (production begins before the 

expiration date for the pre-existing relief in 

its water depth category) and an ultra-deep 

short sidetrack in § 203.0. However, if it does 

not begin production until 2010, it earns no 

RSV because it is too short as a phase 3 ultradeep well to be a qualified ultra-deep well. 

Example 7: Your lease was issued in June 

2004 and expressly incorporates the 

provisions of §§ 203.41 through 203.47 as 

they existed at that time. In January 2005, 

you spud a deep well (well no. 1) with a 

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 one 

qualified phase 2 ultra-deep well on the nonunitized portion of lease A that earns lease 

A an RSV of 35 BCF under § 203.31, one 

qualified deep well on the unitized portion 

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of lease A (drilled after the ultra-deep well 

on the non-unitized portion of that lease) and 

a qualified phase 2 ultra-deep well on lease 

B that earns lease B a 35 BCF RSV under 

§ 203.31. The participating area percentages 

allocate 40 percent of production from both 

of the unit qualified wells to lease A and 60 

percent to lease B. If the non-unitized 

qualified phase 2 ultra-deep well on lease A 

produces 12 BCF, and the unitized qualified 

well on lease A produces 18 BCF, and the 

qualified well on lease B produces 37 BCF, 

then the production volume from and 

allocated to lease A to which the lease A RSV 

applies is 34 BCF [12 + (18 + 37)(0.40)]. The 

production volume allocated to lease B to 

which the lease B RSV applies is 33 BCF [(18 

+ 37)(0.60)]. None of the volumes produced 

from a well that is not within a unit 

participating area may be allocated to other 

leases in the unit. 

(d) You must begin paying royalties 

when the cumulative production of gas 

from all qualified wells on your lease, 

or allocated to your lease under 

paragraph (b) of this section, reaches the 

applicable RSV allowed under § 203.31 

or § 203.41. For the month in which 

cumulative production reaches this 

RSV, you owe royalties on the portion 

of gas production from or allocated to 

your lease that exceeds the RSV 

remaining at the beginning of that 

month. 

§ 203.34 To which production may an RSV 

earned by qualified phase 2 and phase 3 

ultra-deep wells on my lease not be 

applied? 

You may not apply an RSV earned 

under § 203.31: 

(a) To production from completions 

less than 15,000 feet TVD SS, except in 

cases where the qualified well is reperforated in the same reservoir 

previously perforated deeper than 

15,000 feet TVD SS; 

(b) To production from a deep well or 

ultra-deep well on any other lease, 

except as provided in paragraph (c) of 

§ 203.33; 

(c) To any liquid hydrocarbon (oil and 

condensate) volumes; or 

(d) To production from a deep well or 

ultra-deep well that commenced drilling 

before: 

(1) March 26, 2003, on a lease that is 

located entirely or partly in water less 

than 200 meters deep; or 

(2) May 18, 2007, on a lease that is 

located entirely in water more than 200 

meters deep. 

§ 203.35 What administrative steps must I 

take to use the RSV earned by a qualified 

phase 2 or phase 3 ultra-deep well? 

To use an RSV earned under § 203.31: 

(a) You must notify the BSEE Regional 

Supervisor for Production and 

Development in writing of your intent to 

begin drilling operations on all your 

ultra-deep wells. 

(b) Before beginning production, you 

must meet any production measurement 

requirements that the BSEE Regional 

Supervisor for Production and 

Development has determined are 

necessary under 30 CFR part 250, 

subpart L. 

(c)(1) Within 30 days of the beginning 

of production from any wells that would 

become qualified phase 2 or phase 3 

ultra-deep wells by satisfying the 

requirements of this section: 

(i) Provide written notification to the 

BSEE Regional Supervisor for 

Production and Development that 

production has begun; and 

(ii) Request confirmation of the size of 

the RSV earned by your lease. 

(2) If you produced from a qualified 

phase 2 or phase 3 ultra-deep well 

before December 18, 2008, you must 

provide the information in paragraph 

(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 with your 

lease terms. 

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

Example to paragraph (b): If your first 

qualified deep well is a sidetrack with 

a perforated interval whose top is 

16,000 feet TVD SS and earns an RSV 

of 12.5 BCF, and you later drill a 

qualified original deep well to 17,000 

feet TVD SS, the RSV for your lease 

remains at 12.5 BCF and does not 

increase to 15 BCF. However, under 

paragraph (c) of § 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 when 

no part of the lease is within a BSEEapproved unit. Subject to the price 

conditions in § 203.48, you must apply 

the RSV prescribed in § 203.41 as 

required under the following paragraphs 

(b)(1) and (b)(2) of this section. 

(1) You must apply the RSV to the 

earliest gas production occurring on and 

after the later of: 

(i) May 3, 2004, for an RSV earned by 

a qualified deep well or qualified phase 

1 ultra-deep well on a lease that is 

located entirely or partly in water less 

than 200 meters deep; 

(ii) May 18, 2007, for an RSV earned 

by a qualified deep well on a lease that 

is located entirely in water more than 

200 meters deep; or 

(iii) The date that the first qualified 

well that earns your lease the RSV 

begins production (other than test 

production). 

(2) You must apply the RSV to only 

gas production from qualified wells on 

your lease, regardless of their depth, for 

which you have met the requirements in 

§ 203.35 or § 203.44. 

Example 1: On a lease in water less than 

200 meters deep, you began drilling an 

original deep well with a perforated interval 

the top of which is 18,200 feet TVD SS in 

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 cases 

where the qualified deep well is reperforated in the same reservoir 

previously perforated deeper than 

15,000 feet TVD SS; 

(2) Production from a deep well or 

phase 1 ultra-deep well on any other 

lease, except as provided in paragraph 

(c) of this section; 

(3) Any liquid hydrocarbon (oil and 

condensate) volumes; or 

(4) Production from a deep well or 

phase 1 ultra-deep well that commenced 

drilling before: 

(i) March 26, 2003, on a lease that is 

located entirely or partly in water less 

than 200 meters deep, or 

(ii) May 18, 2007, on a lease that is 

located entirely in water more than 200 

meters deep. 

§ 203.44 What administrative steps must I 

take to use the royalty suspension volume? 

(a) You must notify the BSEE Regional 

Supervisor for Production and 

Development in writing of your intent to 

begin drilling operations on all deep 

wells and phase 1 ultra-deep wells; and 

(b) Within 30 days of the beginning of 

production from all wells that would 

become qualified wells by satisfying the 

requirements of this section, you must: 

(1) Provide written notification to the 

BSEE Regional Supervisor for 

Production and Development that 

production has begun; and 

(2) Request confirmation of the size of 

the royalty suspension volume earned 

by your lease. 

(c) Before beginning production, you 

must meet any production measurement 

requirements that the BSEE Regional 

Supervisor for Production and 

Development has determined are 

necessary under 30 CFR part 250, 

subpart L. 

(d) You must provide the information 

in paragraph (b) of this section by 

January 20, 2009, if you produced before 

December 18, 2008, from a qualified 

deep well or qualified phase 1 ultradeep well on a lease that is located 

entirely in water more than 200 meters 

and less than 400 meters deep. 

(e) The BSEE Regional Supervisor for 

Production and Development may 

extend the deadline for beginning 

production for up to one year for a well 

that cannot begin production before the 

applicable date prescribed in the 

definition of ‘‘qualified deep well’’ in 

§ 203.0 if it meets all of the following 

criteria. 

(1) The well otherwise meets the 

criteria in the definition of a qualified 

deep well in § 203.0. 

(2) The delay in production occurred 

after reaching total depth in the well. 

(3) Production (other than test 

production) was expected to begin from 

the well before the applicable deadline 

in the definition of a qualified deep well 

in § 203.0. You must provide a credible 

activity schedule with supporting 

documentation. 

(4) The delay in beginning production 

is for reasons beyond your control, such 

as adverse weather and accidents which 

BSEE deems were unavoidable. 

§ 203.45 If I drill a certified unsuccessful 

well, what royalty relief will my lease earn? 

Your lease may earn a royalty 

suspension supplement. Subject to 

paragraph (d) of this section, the royalty 

suspension supplement is in addition to 

any royalty suspension volume your 

lease may earn under § 203.41. 

(a) If you drill a certified unsuccessful 

well and you satisfy the administrative 

requirements of § 203.47, subject to the 

price conditions in § 203.48, your lease 

earns an RSS shown in the following 

table. The RSS is shown in billions of 

cubic feet of gas equivalent (BCFE) or in 

thousands of cubic feet of gas equivalent 

(MCFE) and is applicable to oil and gas 

production as prescribed in § 203.46. 

If you have a certified unsuccessful well that is:— Then your lease earns an RSS on this volume of oil and gas production as prescribed in this section and § 203.46:— 

(1) An original well and your lease has not produced gas or oil from a 

deep well or an ultra-deep well, 

5 BCFE. 

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If you have a certified unsuccessful well that is:— Then your lease earns an RSS on this volume of oil and gas production as prescribed in this section and § 203.46:— 

(2) A sidetrack (with a sidetrack measured depth of at least 10,000 

feet) and your lease has not produced gas or oil from a deep well or 

an ultra-deep well, 

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 gas 

and oil from, or allocated under a BSEEapproved unit agreement to, your lease. 

(d) Unused royalty suspension 

supplements transfer to a successor 

lessee and expire with the lease. 

(e) You may not apply the RSS 

allowed under § 203.45 to production 

from any other lease, except for 

production allocated to your lease from 

a BSEE-approved unit agreement. If 

your certified unsuccessful well is on a 

lease subject to a BSEE-approved unit 

agreement, the lessees of other leases in 

the unit may not apply any portion of 

the RSS for your lease to production 

from the other leases in the unit. 

(f) You must begin or resume paying 

royalties when cumulative gas and oil 

production from, or allocated under a 

BSEE-approved unit agreement to, your 

lease (excluding any gas produced from 

qualified wells subject to a royalty 

suspension volume allowed under 

§ 203.41) reaches the applicable royalty 

suspension supplement. For the month 

in which the cumulative production 

reaches this royalty suspension 

supplement, you owe royalties on the 

portion of gas or oil production that 

exceeds the amount of the royalty 

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suspension supplement remaining at the 

beginning of that month. 

§ 203.47 What administrative steps do I 

take to obtain and use the royalty 

suspension supplement? 

(a) Before you start drilling a well on 

your lease targeted to a reservoir at least 

18,000 feet TVD SS, you must notify, in 

writing, the BSEE Regional Supervisor 

for Production and Development of your 

intent to begin drilling operations and 

the depth of the target. 

(b) After drilling the well, you must 

provide the BSEE Regional Supervisor 

for Production and Development within 

60 days after reaching the total depth in 

your well: 

(1) Information that allows BSEE to 

confirm that you drilled a certified 

unsuccessful well as defined under 

§ 203.0, including: 

(i) Well log data, if your original well 

or sidetrack does not meet the 

producibility requirements of 30 CFR 

part 550, subpart A; or 

(ii) Well log, well test, seismic, and 

economic data, if your well does meet 

the producibility requirements of 30 

CFR part 550, subpart A; and 

(2) Information that allows BSEE to 

confirm the size of the royalty 

suspension supplement for a sidetrack, 

including sidetrack measured depth and 

supporting documentation. 

(c) If you commenced drilling a well 

that otherwise meets the criteria for a 

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. 

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§ 203.64 How many applications may I file 

on a field or a development project? 

You may file one complete 

application for royalty relief during the 

life of the field or for a development 

project or an expansion project designed 

to produce a reservoir or set of 

reservoirs. However, you may send 

another application if: 

(a) You are eligible to apply for a 

redetermination under § 203.74; 

(b) You apply for royalty relief for an 

expansion project; 

(c) You withdraw the application 

before we make a determination; or 

(d) You apply for end-of-life royalty 

relief. 

§ 203.65 How long will BSEE take to 

evaluate my application? 

(a) We will determine within 20 

working days if your application for 

royalty relief is complete. If your 

application is incomplete, we will 

explain in writing what it needs. If you 

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 

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or the regulations of this chapter (e.g., 

fuel gas). 

(a) For authorized fields, the 

minimum royalty-suspension volumes 

are: 

(1) 17.5 million barrels of oil 

equivalent (MMBOE) for fields in 200 to 

400 meters of water; 

(2) 52.5 MMBOE for fields in 400 to 

800 meters of water; and 

(3) 87.5 MMBOE for fields in more 

than 800 meters of water. 

(b) For development projects, any 

relief we grant applies only to project 

wells and replaces the royalty relief, if 

any, with which we issued your lease. 

(c) If your project is economic given 

the royalty relief with which we issued 

your lease, we will reject the 

application. 

(d) If the lease has earned or may earn 

deep gas royalty relief under §§ 203.40 

through 203.49 or ultra-deep gas royalty 

relief under §§ 203.30 through 203.36, 

we will take the deep gas royalty relief 

or ultra-deep gas royalty relief into 

account in determining whether further 

royalty relief for a development project 

is necessary for production to be 

economic. 

(e) If neither paragraph (c) nor (d) of 

this section apply, the minimum royalty 

suspension volumes are as shown in the 

following table: 

For . . . The minimum royalty suspension volume is . . . Plus . . . 

(1) RS leases in the GOM or leases 

offshore Alaska, 

A volume equal to the combined royalty suspension volumes (or the 

volume equivalent based on the data in your approved application 

for other forms of royalty suspension) with which BSEE issued the 

leases participating in the application that have or plan a well into 

a reservoir identified in the application, 

10 percent of the median of the 

distribution of known recoverable resources upon which 

BSEE based approval of your 

application from all reservoirs 

included in the project. 

(2) Leases offshore Alaska or other 

deep water GOM leases issued in 

sales after November 28, 2000, 

A volume equal to 10 percent of the median of the distribution of 

known recoverable resources upon which BSEE based approval of 

your application from all reservoirs included in the project. 

(f) If your application includes preAct leases in different categories of 

water depth, we apply the minimum 

royalty suspension volume for the 

deepest such lease then assigned to the 

field. We base the water depth and 

makeup of a field on the water-depth 

delineations in the ‘‘Lease Terms and 

Economic Conditions’’ map and the 

‘‘Fields Directory’’ documents and 

updates in effect at the time your 

application is deemed complete. These 

publications are available from the 

BSEE Gulf of Mexico Regional Office. 

(g) You will get a royalty suspension 

volume above the minimum if we 

determine that you need more to make 

the field or development project 

economic. 

(h) For expansion projects, the 

minimum royalty suspension volume 

equals 10 percent of the median of the 

distribution of known recoverable 

resources upon which we based 

approval of your application from all 

reservoirs included in your project plus 

any suspension volumes required under 

§ 203.66. If we determine that your 

expansion project may be economic 

only with more relief, we will determine 

and grant you the royalty suspension 

volume necessary to make the project 

economic. 

(i) The royalty suspension volume 

applicable to specific leases will 

continue through the end of the month 

in which cumulative production reaches 

that volume. You must calculate 

cumulative production from all the 

leases in the authorized field or project 

that are entitled to share the royalty 

suspension volume. 

§ 203.70 What information must I provide 

after BSEE approves relief? 

You must submit reports to us as 

indicated in the following table. 

Sections 203.81, 203.90, and 203.91 

describe what these reports must 

include. The BSEE Regional Office for 

your region will prescribe the formats. 

Required report When due to BSEE Due date extensions 

(a) Fabricator’s confirmation report. Within 18 months after approval of relief. 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 production 

that 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. 

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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 after 

the 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 your 

authorized field still needs additional royalty suspension volume, that volume will be at least the 

combined royalty suspension volume to which all 

added leases on the field are entitled, or the minimum suspension volume of the authorized field, 

whichever is greater, 

(i) You toll the time period for evaluation until you 

modify your application to be consistent with the 

newly constituted field; 

(ii) We have an additional 60 days to review the 

new information; and 

(iii) The assigned pre-Act lease or royalty suspension lease shares the royalty suspension we 

grant to the newly constituted field. An eligible 

lease does not share the royalty suspension we 

grant to the new field. If you do not agree to toll, 

we will have to reject your application due to incomplete information. Production from an assigned eligible lease counts toward the royalty 

suspension volume that we grant under § 203.69 

for your authorized field, but you will not owe royalty on production from the eligible lease until it 

has produced the volume applicable under 30 

CFR 560.114. 

(4) We assign another operator’s 

lease to your field while we are 

evaluating your application, 

We will change your field’s minimum suspension 

volume provided the assigned lease joins the application and is entitled to a larger minimum suspension volume, 

(i) You both toll the time period for evaluation until 

both of you modify your application to be consistent with the new field; 

(ii) We have an additional 60 days to review the 

new information; and 

(iii) The assigned lease(s) shares the royalty suspension we grant to the new field. If you (the 

original applicant) do not agree to toll, the other 

operator’s lease retains any suspension volume it 

has or may share in any relief that we grant by 

filing the short form application specified in 

§ 203.83 and authorized in § 203.82. 

(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 for 

that well will not count toward any royalty suspension volume that we grant under § 203.69 to 

field A. Moreover, past production from that well 

will count toward the royalty suspension volume 

applicable for the lease under 30 CFR 560.114 if 

the well is on an eligible lease or under 30 CFR 

560.124 if the well is on a royalty suspension 

lease. 

(b) When a project has more than one 

lease, the royalty suspension volume for 

each lease equals that lease’s actual 

production from the project (or 

production allocated under an approved 

unit agreement) until total production 

for all leases in the project equals the 

project’s approved royalty suspension 

volume. 

(c) You may receive a royaltysuspension volume only if your entire 

lease is west of 87 degrees, 30 minutes 

West longitude. If the field lies on both 

sides of this meridian, only leases 

located entirely west of the meridian 

will receive a royalty-suspension 

volume. 

§ 203.72 Can my lease receive more than 

one suspension volume? 

Yes. You may apply for royalty relief 

that involves more than one suspension 

volume under § 203.62 in two 

circumstances. 

(a) Each field that includes your lease 

may receive a separate royaltysuspension volume, if it meets the 

evaluation criteria of § 203.67. 

(b) An expansion project on your 

lease may receive a separate royaltysuspension volume, even if we have 

already granted a royalty-suspension 

volume to the field that encompasses 

the project. But the reserves associated 

with the project must not have been part 

of our original determination, and the 

project must meet the evaluation criteria 

of § 203.67. 

§ 203.73 How do suspension volumes 

apply to natural gas? 

You must measure natural gas 

production under the royaltysuspension volume as follows: 5.62 

thousand cubic feet of natural gas, 

measured in accordance with 30 CFR 

part 250, subpart L, equals one barrel of 

oil equivalent. 

§ 203.74 When will BSEE reconsider its 

determination? 

You may request a redetermination 

after we withdraw approval or after you 

renounce royalty relief, unless we 

withdraw approval due to your 

providing false or intentionally 

inaccurate information. Under certain 

conditions you may also request a 

redetermination if we deny your 

application or if you want your 

approved royalty suspension volume to 

change. In these instances, to be eligible 

for a redetermination, at least one of the 

following four conditions must occur. 

(a) You have significant new G&G 

data and you previously have not either 

requested a redetermination or 

reapplied for relief after we withdrew 

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approval or you relinquished royalty 

relief. ‘‘Significant’’ means that the new 

G&G data: 

(1) Results from drilling new wells or 

getting new three-dimensional seismic 

data and information (but not 

reinterpreting old data); 

(2) Did not exist at the time of the 

earlier application; and 

(3) Changes your estimates of gross 

resource size, quality, or projected flow 

rates enough to materially affect the 

results of our earlier determination. 

(b) You demonstrate in your new 

application that the technology that 

most efficiently develops this field or 

lease was not considered or deemed 

feasible in the original application. Your 

newly proposed technology must 

improve the profitability, under 

equivalent market conditions, of the 

field or lease relative to the 

development system proposed in the 

prior application. 

(c) Your current reference price 

decreases by more than 25 percent from 

your base reference price as calculated 

under this paragraph. 

(1) Your current reference price is a 

weighted-average of daily closing prices 

on the NYMEX for light sweet crude oil 

and natural gas over the most recent full 

12 calendar months; 

(2) Your base reference price is a 

weighted average of daily closing prices 

on the NYMEX for light sweet crude oil 

and natural gas for the full 12 calendar 

months preceding the date of your most 

recently approved application for this 

royalty relief; and 

(3) The weighting factors are the 

proportions of the total production 

volume (in BOE) for oil and gas 

associated with the most likely scenario 

(identified in §§ 203.85 and 203.88) 

from your most recently approved 

application for this royalty relief. 

(d) Before starting to build your 

development and production system, 

you have revised your estimated 

development costs, and they are more 

than 120 percent of the eligible 

development costs associated with the 

most likely scenario from your most 

recently approved application for this 

royalty relief. 

§ 203.75 What risk do I run if I request a 

redetermination? 

If you request a redetermination after 

we have granted you a suspension 

volume, you could lose some or all of 

the previously granted relief. This can 

happen because you must file a new 

complete application and pay the 

required fee, as discussed in § 203.62. 

We will evaluate your application under 

§ 203.67 using the conditions prevailing 

at the time of your redetermination 

request. In our evaluation, we may find 

that you should receive a larger, 

equivalent, smaller, or no suspension 

volume. This means we could find that 

you do not qualify for the amount of 

relief previously granted or for any relief 

at all. 

§ 203.76 When might BSEE withdraw or 

reduce the approved size of my relief? 

We will withdraw approval of relief 

for any of the following reasons. 

(a) You change the type of 

development system proposed in your 

application (e.g., change from a fixed 

platform to floating production system, 

or from an independent development 

and production system to one with 

subsea wells tied back to a host 

production facility, etc.). 

(b) You do not start building the 

proposed development and production 

system within 18 months of the date we 

approved your application, unless the 

BSEE Director grants you an extension 

under § 203.79(c). If you start building 

the proposed system and then suspend 

its construction before completion, and 

you do not restart continuous building 

of the proposed system within 18 

months of our approval, we will 

withdraw the relief we granted. 

(c) Your actual development costs are 

less than 80 percent of the eligible 

development costs estimated in your 

application’s most likely scenario, and 

you do not report that fact in your postproduction development report 

(§ 203.70). Development costs are those 

expenditures defined in § 203.89(b) 

incurred between the application 

submission date and start of production. 

If you report this fact in the postproduction development report, you 

may retain the lesser of 50 percent of the 

original royalty suspension volume or 

50 percent of the median of the 

distribution of the potentially 

recoverable resources anticipated in 

your application. 

(d) We granted you a royaltysuspension volume after you qualified 

for a redetermination under § 203.74(c), 

and we find out your actual 

development costs are less than 90 

percent of the eligible development 

costs associated with your application’s 

most likely scenario. Development costs 

are those expenditures defined in 

§ 203.89(b) incurred between your 

application submission date and start of 

production. 

(e) You do not send us the fabrication 

confirmation report or the postproduction development report, or you 

provide false or intentionally inaccurate 

information that was material to our 

granting royalty relief under this 

section. You must pay royalties and 

late-payment interest determined under 

30 U.S.C. 1721 and 30 CFR 1218.54 on 

all volumes for which you used the 

royalty suspension. You also may be 

subject to penalties under other 

provisions of law. 

§ 203.77 May I voluntarily give up relief if 

conditions change? 

Yes, you may voluntarily give up 

relief by sending a letter to that effect to 

the BSEE Regional office for your 

region. 

§ 203.78 Do I keep relief approved by 

BSEE under this part for my lease, unit or 

project if prices rise significantly? 

If prices rise above a base price 

threshold for light sweet crude oil or 

natural gas, you must pay full royalties 

on production otherwise subject to 

royalty relief approved by BSEE under 

§§ 203.60–203.77 for your lease, unit or 

project as prescribed in this section. 

(a) The following table shows the base 

price threshold for various types of 

leases, subject to paragraph (b) of this 

section. Note that, for post-November 

2000 deepwater leases in the GOM, 

price thresholds apply on a lease basis, 

so different leases on the same 

development project or expansion 

project approved for royalty relief may 

have different price thresholds. 

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. 

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(b) An exception may occur if we 

determine that the price thresholds in 

paragraphs (a)(2) or (a)(3) of this section 

mean the royalty suspension volume set 

under § 203.69 and in lease terms would 

provide inadequate encouragement to 

increase production or development, in 

which circumstance we could specify a 

different set of price thresholds on a 

case-by-case basis. 

(c) Suppose your base oil price 

threshold set under paragraph (a) is 

$28.00 per barrel, and the daily closing 

NYMEX light sweet crude oil prices for 

the previous calendar year exceeds 

$28.00 per barrel, as adjusted in 

paragraph (h) of this section. In this 

case, we retract the royalty relief 

authorized in this subpart and you 

must: 

(1) Pay royalties on all oil production 

for the previous year at the lease 

stipulated royalty rate plus interest 

(under 30 U.S.C. 1721 and 30 CFR 

1218.54) by March 31 of the current 

calendar year, and 

(2) Pay royalties on all your oil 

production in the current year. 

(d) Suppose your base gas price 

threshold set under paragraph (a) is 

$3.50 per million British thermal units 

(Btu), and the daily closing NYMEX 

light sweet crude oil prices for the 

previous calendar year exceeds $3.50 

per million Btu, as adjusted in 

paragraph (h) of this section. In this 

case, we retract the royalty relief 

authorized in this subpart and you 

must: 

(1) Pay royalties on all gas production 

for the previous year at the lease 

stipulated royalty rate plus interest 

(under 30 U.S.C. 1721 and 30 CFR 

1218.54) by March 31 of the current 

calendar year, and 

(2) Pay royalties on all your gas 

production in the current year. 

(e) Production under both paragraphs 

(c) and (d) of this section counts as part 

of the royalty-suspension volume. 

(f) You are entitled to a refund or 

credit, with interest, of royalties paid on 

any production (that counts as part of 

the royalty-suspension volume): 

(1) Of oil if the arithmetic average of 

the closing prices for the current 

calendar year is $28.00 per barrel or 

less, as adjusted in paragraph (h) of this 

section, and 

(2) Of gas if the arithmetic average of 

the closing natural gas prices for the 

current calendar year is $3.50 per 

million Btu or less, as adjusted in 

paragraph (h) of this section. 

(g) You must follow our regulations in 

the Office of Natural Resources 

Revenue, 30 CFR chapter XII, for 

receiving refunds or credits. 

(h) We change the prices referred to 

in paragraphs (c), (d), and (f) of this 

section periodically. For pre-Act leases, 

these prices change during each 

calendar year after 1994 by the 

percentage that the implicit price 

deflator for the gross domestic product 

changed during the preceding calendar 

year. For post-November 2000 

deepwater leases, these prices change as 

indicated in the lease instrument or in 

the Notice of Sale under which we 

issued the lease. 

§ 203.79 How do I appeal BSEE’s 

decisions related to royalty relief for a 

deepwater lease or a development or 

expansion project? 

(a) Once we have designated your 

lease as part of a field and notified you 

and other affected operators of the 

designation, you can request 

reconsideration by sending the BSEE 

Director a letter within 15 days that also 

states your reasons. The BSEE Director’s 

response is the final agency action. 

(b) Our decisions on your application 

for relief from paying royalty under 

§ 203.67 and the royalty-suspension 

volumes under § 203.69 are final agency 

actions. 

(c) If you cannot start construction by 

the deadline in § 203.76(b) for reasons 

beyond your control (e.g., strike at the 

fabrication yard), you may request an 

extension up to 1 year by writing the 

BSEE Director and stating your reasons. 

The BSEE Director’s response is the 

final agency action. 

(d) We will notify you of all final 

agency actions by certified mail, return 

receipt requested. Final agency actions 

are not subject to appeal to the Interior 

Board of Land Appeals under 30 CFR 

part 290 and 43 CFR part 4. They are 

judicially reviewable under section 

10(a) of the Administrative Procedure 

Act (5 U.S.C. 702) only if you file an 

action within 30 days of the date you 

receive our decision. 

§ 203.80 When can I get royalty relief if I 

am not eligible for royalty relief under other 

sections in the subpart? 

We may grant royalty relief when it 

serves the statutory purposes 

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

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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 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 

(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; 

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(5) Civil or criminal fines or penalties; 

(6) Fees for your royalty relief 

application; and 

(7) Costs associated with existing 

obligations (e.g., royalty overrides or 

other forms of payment for acquiring the 

lease, depreciation on previously 

acquired equipment or facilities). 

(c) We may, in reviewing and 

evaluating your application, disallow 

costs when you have not shown they are 

necessary to operate the lease, or if they 

are inconsistent with end-of-life 

operations. 

§ 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 survey 

lines reflecting any available state-ofthe-art processing technique in a format 

readable by BSEE and specified by the 

deep water royalty relief guidelines; 

(2) Interpreted 2D/3D seismic survey 

lines reflecting any available state-ofthe-art processing technique identifying 

all known and prospective pay 

horizons, wells, and fault cuts; 

(3) Digital velocity surveys in the 

format of the GOM region’s letter to 

lessees of 10/1/90; 

(4) Plat map of ‘‘shot points;’’ and 

(5) ‘‘Time slices’’ of potential 

horizons. 

(b) Well data which includes: 

(1) Hard copies of all well logs in 

which— 

(i) The 1-inch electric log shows pay 

zones and pay counts and lithologic and 

paleo correlation markers at least every 

500-feet, 

(ii) The 1-inch type log shows missing 

sections from other logs where faulting 

occurs, 

(iii) The 5-inch electric log shows pay 

zones and pay counts and labeled points 

used in establishing resistivity of the 

formation, 100 percent water saturated 

(Ro) and the resistivity of the 

undisturbed formation (Rt), and 

(iv) The 5-inch porosity logs show pay 

zones and pay counts and labeled points 

used in establishing reservoir porosity 

or labeled points showing values used 

in calculating reservoir porosity such as 

bulk density or transit time; 

(2) Digital copies of all well logs 

spudded before December 1, 1995; 

(3) Core data, if available; 

(4) Well correlation sections; 

(5) Pressure data; 

(6) Production test results; 

(7) Pressure-volume-temperature 

analysis, if available; and 

(8) A table listing the wells and 

completions, and indicating which 

sands and fault blocks will be targeted 

for completion or recompletion. 

(c) Map interpretations which 

includes for each reservoir in the field: 

(1) Structure maps consisting of top 

and base of sand maps showing well 

and seismic shot point locations; 

(2) Isopach maps for net sand, net oil, 

net gas, all with well locations; 

(3) Maps indicating well surface and 

bottom hole locations, location of 

development facilities, and shot points; 

and 

(4) An explanation for excluding the 

reservoirs you are not planning to 

develop. 

(d) Reservoir-specific data which 

includes: 

(1) Probability of reservoir occurrence 

with hydrocarbons; 

(2) Probability the hydrocarbon in the 

reservoir is all oil and the probability it 

is all gas; 

(3) Distributions or point estimates 

(accompanied by explanations of why 

distributions less appropriately reflect 

the uncertainty) for the parameters used 

to estimate reservoir size, i.e., acres and 

net thickness; 

(4) Most likely values for porosity, salt 

water saturation, volume factor for oil 

formation, and volume factor for gas 

formation; 

(5) Distributions or point estimates 

(accompanied by explanations of why 

distributions less appropriately reflect 

the uncertainty) for recovery efficiency 

(in percent) and oil or gas recovery (in 

stock-tank-barrels per acre-foot or in 

thousands of cubic feet per acre foot); 

(6) A gas/oil ratio distribution or point 

estimate (accompanied by explanations 

of why distributions less appropriately 

reflect the uncertainty) for each 

reservoir; 

(7) A yield distribution or point 

estimate (accompanied by explanations 

of why distributions less appropriately 

reflect the uncertainty) for each gas 

reservoir; and 

(8) Reserve or resource distribution by 

reservoir. 

(e) Aggregated reserve and resource 

data which includes: 

(1) The aggregated distributions for 

reserves and resources (in BOE) and oil 

fraction for your field computed by the 

resource module of our RSVP model; 

(2) A description of anticipated 

hydrocarbon quality (i.e., specific 

gravity); and 

(3) The ranges within the aggregated 

distribution for reserves and resources 

that define the development and 

production scenarios presented in the 

engineering and production reports. 

Typically there will be three ranges 

specified by two positive reserve and 

resource points on the aggregated 

distribution. The range at the low end 

of the distribution will be associated 

with the conservative development and 

production scenario; the middle range 

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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 consistent 

with each one of up to three fielddevelopment scenarios and production 

profiles (conservative, most likely, 

optimistic). You should express costs in 

constant real dollar terms for the base 

year. You may also express the 

uncertainty of each cost estimate with a 

minimum and maximum percentage of 

the base value. 

(g) A spending schedule. You should 

provide costs for each year (in real 

dollars) for each category in paragraphs 

(a) through (f) of this section. 

(h) A summary of other costs which 

are ineligible for evaluating your need 

for relief. These costs cover: 

(1) Expenses before first discovery on 

the field; 

(2) Cash bonuses; 

(3) Fees for royalty relief applications; 

(4) Lease rentals, royalties, and 

payments of net profit share and net 

revenue share; 

(5) Legal expenses; 

(6) Damages and losses; 

(7) Taxes; 

(8) Interest or finance charges, 

including those embedded in equipment 

leases; 

(9) Fines or penalties; and 

(10) Money spent on previously 

existing obligations (e.g., royalty 

overrides or other forms of payment for 

acquiring a financial position in a lease, 

expenditures for plugging wells and 

removing and abandoning facilities that 

existed on the application submission 

date). 

§ 203.90 What is in a fabricator’s 

confirmation report? 

This report shows you have 

committed in a timely way to the 

approved system for production. This 

report must include the following (or its 

equivalent for unconventionally 

acquired systems): 

(a) A copy of the contract(s) under 

which the fabrication yard is building 

the approved system for you; 

(b) A letter from the contractor 

building the system to the BSEE 

Regional Director for your region 

certifying when construction started on 

your system; and 

(c) Evidence of an appropriate down 

payment or equal action that you’ve 

started acquiring the approved system. 

§ 203.91 What is in a post-production 

development report? 

For each cost category in the deep 

water cost report, you must compare 

actual costs up to the date when 

production starts to your planned preproduction costs. If your application 

included more than one development 

scenario, you need to compare actual 

costs with those in your scenario of 

most likely development. Also, you 

must have this report certified by an 

independent CPA according to 

§ 203.81(c). 

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Subpart C—Federal and Indian Oil 

[Reserved] 

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 Rightsof-Way 

250.1000 General requirements. 

250.1001 Definitions. 

250.1002 Design requirements for DOI 

pipelines. 

250.1003 Installation, testing, and repair 

requirements for DOI pipelines. 

250.1004 Safety equipment requirements 

for DOI pipelines. 

250.1005 Inspection requirements for DOI 

pipelines. 

250.1006 How must I decommission and 

take out of service a DOI pipeline? 

250.1007 What to include in applications. 

250.1008 Reports. 

250.1009 Requirements to obtain pipeline 

right-of-way grants. 

250.1010 General requirements for pipeline 

right-of-way holders. 

250.1011 [Reserved] 

250.1012 Required payments for pipeline 

right-of-way holders. 

250.1013 Grounds for forfeiture of pipeline 

right-of-way grants. 

250.1014 When pipeline right-of-way grants 

expire. 

250.1015 Applications for pipeline right-ofway grants. 

250.1016 Granting pipeline rights-of-way. 

250.1017 Requirements for construction 

under pipeline right-of-way grants. 

250.1018 Assignment of pipeline right-ofway grants. 

250.1019 Relinquishment of pipeline rightof-way grants. 

Subpart K—Oil and Gas Production 

Requirements 

General 

250.1150 What are the general reservoir 

production requirements? 

Well Tests and Surveys 

250.1151 How often must I conduct well 

production tests? 

250.1152 How do I conduct well tests? 

250.1153 [Reserved] 

Classifying Reservoirs 

250.1154 [Reserved] 

250.1155 [Reserved] 

Approvals Prior to Production 

250.1156 What steps must I take to receive 

approval to produce within 500 feet of a 

unit or lease line? 

250.1157 How do I receive approval to 

produce gas-cap gas from an oil reservoir 

with an associated gas cap? 

250.1158 How do I receive approval to 

downhole commingle hydrocarbons? 

Production Rates 

250.1159 May the Regional Supervisor limit 

my well or reservoir production rates? 

Flaring, Venting, and Burning Hydrocarbons 

250.1160 When may I flare or vent gas? 

250.1161 When may I flare or vent gas for 

extended periods of time? 

250.1162 When may I burn produced liquid 

hydrocarbons? 

250.1163 How must I measure gas flaring or 

venting volumes and liquid hydrocarbon 

burning volumes, and what records must 

I maintain? 

250.1164 What are the requirements for 

flaring or venting gas containing H2S? 

Other Requirements 

250.1165 What must I do for enhanced 

recovery operations? 

250.1166 What additional reporting is 

required for developments in the Alaska 

OCS Region? 

250.1167 What information must I submit 

with forms and for approvals? 

Subpart L—Oil and Gas Production 

Measurement, Surface Commingling, and 

Security 

250.1200 Question index table. 

250.1201 Definitions. 

250.1202 Liquid hydrocarbon 

measurement. 

250.1203 Gas measurement. 

250.1204 Surface commingling. 

250.1205 Site security. 

Subpart M—Unitization 

250.1300 What is the purpose of this 

subpart? 

250.1301 What are the requirements for 

unitization? 

250.1302 What if I have a competitive 

reservoir on a lease? 

250.1303 How do I apply for voluntary 

unitization? 

250.1304 How will BSEE require 

unitization? 

Subpart N—Outer Continental Shelf Civil 

Penalties 

Outer Continental Shelf Lands Act Civil 

Penalties 

250.1400 How does BSEE begin the civil 

penalty process? 

250.1401 Index table. 

250.1402 Definitions. 

250.1403 What is the maximum civil 

penalty? 

250.1404 Which violations will BSEE 

review for potential civil penalties? 

250.1405 When is a case file developed? 

250.1406 When will BSEE notify me and 

provide penalty information? 

250.1407 How do I respond to the letter of 

notification? 

250.1408 When will I be notified of the 

Reviewing Officer’s decision? 

250.1409 What are my appeal rights? 

Federal Oil and Gas Royalty Management 

Act Civil Penalties Definitions 

250.1450 What definitions apply to this 

subpart? 

Penalties After a Period To Correct 

250.1451 What may BSEE do if I violate a 

statute, regulation, order, or lease term 

relating to a Federal oil and gas lease? 

250.1452 What if I correct the violation? 

250.1453 What if I do not correct the 

violation? 

250.1454 How may I request a hearing on 

the record on a Notice of 

Noncompliance? 

250.1455 Does my request for a hearing on 

the record affect the penalties? 

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250.1456 May I request a hearing on the 

record regarding the amount of a civil 

penalty if I did not request a hearing on 

the Notice of Noncompliance? 

Penalties Without a Period To Correct 

250.1460 May I be subject to penalties 

without prior notice and an opportunity 

to correct? 

250.1461 How will BSEE inform me of 

violations without a period to correct? 

250.1462 How may I request a hearing on 

the record on a Notice of Noncompliance 

regarding violations without a period to 

correct? 

250.1463 Does my request for a hearing on 

the record affect the penalties? 

250.1464 May I request a hearing on the 

record regarding the amount of a civil 

penalty if I did not request a hearing on 

the Notice of Noncompliance? 

General Provisions 

250.1470 How does BSEE decide what the 

amount of the penalty should be? 

250.1471 Does the penalty affect whether I 

owe interest? 

250.1472 How will the Office of Hearings 

and Appeals conduct the hearing on the 

record? 

250.1473 How may I appeal the 

Administrative Law Judge’s decision? 

250.1474 May I seek judicial review of the 

decision of the Interior Board of Land 

Appeals? 

250.1475 When must I pay the penalty? 

250.1476 Can BSEE reduce my penalty once 

it is assessed? 

250.1477 How may BSEE collect the 

penalty? 

Criminal Penalties 

250.1480 May the United States criminally 

prosecute me for violations under 

Federal oil and gas leases? 

Bonding Requirements 

250.1490 What standards must my BOEMspecified surety instrument meet? 

250.1491 How will BOEM determine the 

amount of my bond or other surety 

instrument? 

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—WHERE TO FIND INFORMATION FOR CONDUCTING OPERATIONS

For information about . . . Refer to . . . 

(1) Applications for permit to drill, 30 CFR 250, subpart D. 

(2) Development and Production Plans (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 island 

used for drilling, well completion, wellworkover, or production operations. 

(4) As used in §§ 250.900 through 

250.921, means all installations or 

devices permanently or temporarily 

attached to the seabed. They are used 

for exploration, development, and 

production activities for oil, gas, or 

sulphur and emit or have the potential 

to emit any air pollutant from one or 

more sources. They include all floating 

production systems (FPSs), including 

column-stabilized-units (CSUs); floating 

production, storage and offloading 

facilities (FPSOs); tension-leg platforms 

(TLPs); spars, etc. During production, 

multiple installations or devices are a 

single facility if the installations or 

devices are at a single site. Any vessel 

used to transfer production from an 

offshore facility is part of the facility 

while it is physically attached to the 

facility. 

Flaring means the burning of natural 

gas as it is released into the atmosphere. 

Gas reservoir means a reservoir that 

contains hydrocarbons predominantly 

in a gaseous (single-phase) state. 

Gas-well completion means a well 

completed in a gas reservoir or in the 

associated gas-cap of an oil reservoir. 

Geological and geophysical (G&G) 

explorations mean those G&G surveys 

on your lease or unit that use seismic 

reflection, seismic refraction, magnetic, 

gravity, gas sniffers, coring, or other 

systems to detect or imply the presence 

of oil, gas, or sulphur in commercial 

quantities. 

Governor means the Governor of a 

State, or the person or entity designated 

by, or under, State law to exercise the 

powers granted to such Governor under 

the Act. 

H2S absent means: 

(1) Drilling, logging, coring, testing, or 

producing operations have confirmed 

the absence of H2S in concentrations 

that could potentially result in 

atmospheric concentrations of 20 ppm 

or more of H2S; or 

(2) Drilling in the surrounding areas 

and correlation of geological and 

seismic data with equivalent 

stratigraphic units have confirmed an 

absence of H2S throughout the area to be 

drilled. 

H2S present means drilling, logging, 

coring, testing, or producing operations 

have confirmed the presence of H2S in 

concentrations and volumes that could 

potentially result in atmospheric 

concentrations of 20 ppm or more of 

H2S. 

H2S unknown means the designation 

of a zone or geologic formation where 

neither the presence nor absence of H2S 

has been confirmed. 

Human environment means the 

physical, social, and economic 

components, conditions, and factors 

that interactively determine the state, 

condition, and quality of living 

conditions, employment, and health of 

those affected, directly or indirectly, by 

activities occurring on the OCS. 

Interpreted geological information 

means geological knowledge, often in 

the form of schematic cross sections, 3- 

dimensional representations, and maps, 

developed by determining the geological 

significance of data and analyzed 

geological information. 

Interpreted geophysical information 

means geophysical knowledge, often in 

the form of schematic cross sections, 3- 

dimensional representations, and maps, 

developed by determining the geological 

significance of geophysical data and 

analyzed geophysical information. 

Lease means an agreement that is 

issued under section 8 or maintained 

under section 6 of the Act and that 

authorizes exploration for, and 

development and production of, 

minerals. The term also means the area 

covered by that authorization, 

whichever the context requires. 

Lease term pipelines mean those 

pipelines owned and operated by a 

lessee or operator that are completely 

contained within the boundaries of a 

single lease, unit, or contiguous (not 

cornering) leases of that lessee or 

operator. 

Lessee means a person who has 

entered into a lease with the United 

States to explore for, develop, and 

produce the leased minerals. The term 

lessee also includes the BOEMapproved assignee of the lease, and the 

owner or the BOEM-approved assignee 

of operating rights for the lease. 

Major Federal action means any 

action or proposal by the Secretary that 

is subject to the provisions of section 

102(2)(C) of the National Environmental 

Policy Act of 1969, 42 U.S.C. (2)(C) (i.e., 

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an action that will have a significant 

impact on the quality of the human 

environment requiring preparation of an 

environmental impact statement under 

section 102(2)(C) of the National 

Environmental Policy Act). 

Marine environment means the 

physical, atmospheric, and biological 

components, conditions, and factors 

that interactively determine the 

productivity, state, condition, and 

quality of the marine ecosystem. These 

include the waters of the high seas, the 

contiguous zone, transitional and 

intertidal areas, salt marshes, and 

wetlands within the coastal zone and on 

the OCS. 

Material remains mean physical 

evidence of human habitation, 

occupation, use, or activity, including 

the site, location, or context in which 

such evidence is situated. 

Maximum efficient rate (MER) means 

the maximum sustainable daily oil or 

gas withdrawal rate from a reservoir that 

will permit economic development and 

depletion of that reservoir without 

detriment to ultimate recovery. 

Maximum production rate (MPR) 

means the approved maximum daily 

rate at which oil or gas may be produced 

from a specified oil-well or gas-well 

completion. 

Minerals include oil, gas, sulphur, 

geopressured-geothermal and associated 

resources, and all other minerals that 

are authorized by an Act of Congress to 

be produced. 

Natural resources include, without 

limiting the generality thereof, oil, gas, 

and all other minerals, and fish, shrimp, 

oysters, clams, crabs, lobsters, sponges, 

kelp, and other marine animal and plant 

life but does not include water power or 

the use of water for the production of 

power. 

Nonattainment area means, for any 

air pollutant, an area that is shown by 

monitored data or that is calculated by 

air quality modeling (or other methods 

determined by the Administrator of EPA 

to be reliable) to exceed any primary or 

secondary ambient air quality standard 

established by EPA. 

Nonsensitive reservoir means a 

reservoir in which ultimate recovery is 

not decreased by high reservoir 

production rates. 

Oil reservoir means a reservoir that 

contains hydrocarbons predominantly 

in a liquid (single-phase) state. 

Oil reservoir with an associated gas 

cap means a reservoir that contains 

hydrocarbons in both a liquid and 

gaseous (two-phase) state. 

Oil-well completion means a well 

completed in an oil reservoir or in the 

oil accumulation of an oil reservoir with 

an associated gas cap. 

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 deems 

it 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 ............................................ § 250.1156(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 of 

identifying a potential hydrocarbonbearing formation. 

(5) You demonstrate that additional 

time is necessary to: 

(i) Complete current processing or 

interpretation of existing geophysical 

data or information; 

(ii) Acquire, process, or interpret new 

geophysical data or information; or 

(iii) Drill into the potential 

hydrocarbon-bearing formation 

identified as a result of the activities 

conducted in paragraphs (b)(2), (b)(4), 

and (b)(5) of this section. 

(c) The Regional Supervisor may grant 

an SOO to conduct additional geological 

and geophysical data analysis that may 

lead to the drilling of a well below 

25,000 feet true vertical depth below the 

datum at mean sea level (TVD SS) when 

all of the following conditions are met: 

(1) The lease was issued with a 

primary lease term of: 

(i) Five years; or 

(ii) Eight years with a requirement to 

drill within 5 years. 

(2) Before the end of the fifth year of 

the primary term, you or your 

predecessor in interest must have 

acquired and interpreted geophysical 

information that: 

(i) Indicates that all or a portion of a 

potential hydrocarbon-bearing 

formation lies below 25,000 feet TVD 

SS; and 

(ii) Includes full 3–D depth migration 

over the entire lease area. 

(3) Before requesting the suspension, 

you have conducted or are conducting 

additional data processing or 

interpretation of the geophysical 

information with the objective of 

identifying a potential hydrocarbonbearing geologic structure or 

stratigraphic trap lying below 25,000 

feet TVD SS. 

(4) You demonstrate that additional 

time is necessary to: 

(i) Complete current processing or 

interpretation of existing geophysical 

data or information; 

(ii) Acquire, process, or interpret new 

geophysical or geological data or 

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information that would affect the 

decision to drill the same geologic 

structure or stratigraphic trap, as 

determined by the Regional Supervisor, 

identified in paragraphs (c)(2) and (c)(3) 

of this section; or 

(iii) Drill a well below 25,000 feet 

TVD SS into the geologic structure or 

stratigraphic trap identified as a result 

of the activities conducted in 

paragraphs (c)(2), (c)(3), and (c)(4)(i) and 

(ii) of this section. 

§ 250.176 Does a suspension affect my 

royalty payment? 

A directed suspension may affect the 

payment of rental or royalties for the 

lease as provided in 30 CFR 1218.154. 

§ 250.177 What additional requirements 

may the Regional Supervisor order for a 

suspension? 

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 (H2S) gas, as defined in 

§ 250.490(l). 

(6) All collisions that result in 

property or equipment damage greater 

than $25,000. ‘‘Collision’’ means the act 

of a moving vessel (including an 

aircraft) striking another vessel, or 

striking a stationary vessel or object 

(e.g., a boat striking a drilling rig or 

platform). ‘‘Property or equipment 

damage’’ means the cost of labor and 

material to restore all affected items to 

their condition before the damage, 

including, but not limited to, the OCS 

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 

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panel meeting. A subpoena may not 

require a person to attend a panel 

meeting held at a location more than 

100 miles from where a subpoena is 

served. 

(d) Any person giving testimony may 

request compensation for mileage, and 

fees for services, within 90 days after 

the panel meeting. The compensated 

expenses must be similar to mileage and 

fees the U.S. District Courts allow. 

§ 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 period 

of 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 with 

safety or environmental protection requirements, 

Geophysical data, Geological 

data, Interpreted G&G information, Processed geological information, Analyzed geological information, 

60 days after BSEE receives the 

data or information, if the Regional Supervisor deems it necessary, 

BSEE will release the data and 

information earlier than 60 days 

if the Regional Supervisor determines it is needed by affected States to make decisions 

under 30 CFR 550, subpart B. 

The Regional Supervisor will reconsider earlier release if you 

satisfy him/her that it would unduly damage your competitive 

position. 

(3) Your lease is no longer in effect, Geophysical data, Geological 

data, Processed G&G information Interpreted G&G information, Analyzed geological information, 

When your lease terminates, This release time applies only if 

the provisions in this table governing high-resolution systems 

and the provisions in 30 CFR 

552.7 do not apply. The release 

time applies to the geophysical 

data and information only if acquired postlease for a lessee’s 

exclusive use. 

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If . . . BSEE will release . . . At this time . . . Special provisions . . . 

(4) Your lease is still in effect, Geophysical data, Processed 

geophysical information, Interpreted G&G information, 

10 years after you submit the 

data and information, 

This release time applies only if 

the provisions in this table governing high-resolution systems 

and the provisions in 30 CFR 

552.7 do not apply. This release time applies to the geophysical data and information 

only if acquired postlease for a 

lessee’s exclusive use. 

(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 if 

the provisions in this table governing high-resolution systems 

and the provisions in 30 CFR 

552.7 do not apply. If the primary term specified in the lease 

is extended under the heading 

of ‘‘Suspensions’’ in this subpart, the extension applies to 

this provision. 

(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 production 

or 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 the 

permit; 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 

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the listed documents. In each instance, 

the applicable document is the specific 

edition or specific edition and 

supplement or addendum cited in this 

section. 

(c) Under §§ 250.141 and 250.142, you 

may comply with a later edition of a 

specific document incorporated by 

reference, provided: 

(1) You show that complying with the 

later edition provides a degree of 

protection, safety, or performance equal 

to or better than would be achieved by 

compliance with the listed edition; and 

(2) You obtain the prior written 

approval for alternative compliance 

from the authorized BSEE official. 

(d) You may inspect these documents 

at the Bureau of Safety and 

Environmental Enforcement, 381 Elden 

Street, Room 3313, Herndon, Virginia 

20170; phone: 703–787–1587; or at the 

National Archives and Records 

Administration (NARA). For 

information on the availability of this 

material at NARA, call 202–741–6030, 

or go to: 

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; 

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(16) API MPMS, Chapter 5—Metering, 

Section 1—General Considerations for 

Measurement by Meters, Fourth Edition, 

September 2005; incorporated by 

reference at § 250.1202; 

(17) API MPMS, Chapter 5—Metering, 

Section 2—Measurement of Liquid 

Hydrocarbons by Displacement Meters, 

Third Edition, September 2005; 

incorporated by reference at § 250.1202; 

(18) API MPMS Chapter 5—Metering, 

Section 3—Measurement of Liquid 

Hydrocarbons by Turbine Meters, Fifth 

Edition, September 2005; incorporated 

by reference at § 250.1202; 

(19) API MPMS, Chapter 5—Metering, 

Section 4—Accessory Equipment for 

Liquid Meters, Fourth Edition, 

September 2005; incorporated by 

reference at § 250.1202; 

(20) API MPMS, Chapter 5—Metering, 

Section 5—Fidelity and Security of 

Flow Measurement Pulsed-Data 

Transmission Systems, Second Edition, 

August 2005; incorporated by reference 

at § 250.1202; 

(21) API MPMS, Chapter 6—Metering 

Assemblies, Section 1—Lease 

Automatic Custody Transfer (LACT) 

Systems, Second Edition, May 1991; 

reaffirmed, April 2007; incorporated by 

reference at § 250.1202; 

(22) API MPMS, Chapter 6—Metering 

Assemblies, Section 6—Pipeline 

Metering Systems, Second Edition, May 

1991; reaffirmed, February 2007; 

incorporated by reference at § 250.1202; 

(23) API MPMS, Chapter 6—Metering 

Assemblies, Section 7—Metering 

Viscous Hydrocarbons, Second Edition, 

May 1991; reaffirmed, April 2007; 

incorporated by reference at § 250.1202; 

(24) API MPMS, Chapter 7— 

Temperature Determination, First 

Edition, June 2001; reaffirmed, March 

2007; incorporated by reference at 

§ 250.1202; 

(25) API MPMS, Chapter 8— 

Sampling, Section 1—Standard Practice 

for Manual Sampling of Petroleum and 

Petroleum Products, Third Edition, 

October 1995; reaffirmed, March 2006; 

incorporated by reference at § 250.1202; 

(26) API MPMS, Chapter 8— 

Sampling, Section 2—Standard Practice 

for Automatic Sampling of Liquid 

Petroleum and Petroleum Products, 

Second Edition, October 1995; 

reaffirmed, June 2005; incorporated by 

reference at § 250.1202; 

(27) API MPMS, Chapter 9—Density 

Determination, Section 1—Standard 

Test Method for Density, Relative 

Density (Specific Gravity), or API 

Gravity of Crude Petroleum and Liquid 

Petroleum Products by Hydrometer 

Method, Second Edition, December 

2002; reaffirmed October 2005; 

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; 

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(46) API MPMS, Chapter 21—Flow 

Measurement Using Electronic Metering 

Systems, Section 1—Electronic Gas 

Measurement, First Edition, August 

1993; reaffirmed, July 2005; 

incorporated by reference at § 250.1203; 

(47) API RP 2A–WSD, Recommended 

Practice for Planning, Designing and 

Constructing Fixed Offshore Platforms— 

Working Stress Design, Twenty-first 

Edition, December 2000; Errata and 

Supplement 1, December 2002; Errata 

and Supplement 2, September 2005; 

Errata and Supplement 3, October 2007; 

incorporated by reference at §§ 250.901, 

250.908, 250.919, and 250.920; 

(48) API RP 2D, Operation and 

Maintenance of Offshore Cranes, Sixth 

Edition, May 2007; incorporated by 

reference at § 250.108; 

(49) API RP 2FPS, RP for Planning, 

Designing, and Constructing Floating 

Production Systems; First Edition, 

March 2001; incorporated by reference 

at § 250.901; 

(50) API RP 2I, In-Service Inspection 

of Mooring Hardware for Floating 

Structures; Third Edition, April 2008; 

incorporated by reference at § 250.901(a) 

and (d); 

(51) API RP 2RD, Recommended 

Practice for Design of Risers for Floating 

Production Systems (FPSs) and 

Tension-Leg Platforms (TLPs), First 

Edition, June 1998; reaffirmed, May 

2006, Errata, June 2009; incorporated by 

reference at §§ 250.800; 250.901 and 

250.1002; 

(52) API RP 2SK, Design and Analysis 

of Stationkeeping Systems for Floating 

Structures, Third Edition, October 2005, 

Addendum, May 2008; incorporated by 

reference at §§ 250.800 and 250.901; 

(53) API RP 2SM, Recommended 

Practice for Design, Manufacture, 

Installation, and Maintenance of 

Synthetic Fiber Ropes for Offshore 

Mooring, First Edition, March 2001, 

Addendum, May 2007; incorporated by 

reference at § 250.901; 

(54) API RP 2T, Recommended 

Practice for Planning, Designing, and 

Constructing Tension Leg Platforms, 

Second Edition, August 1997; 

incorporated by reference at § 250.901; 

(55) API RP 14B, Recommended 

Practice for Design, Installation, Repair 

and Operation of Subsurface Safety 

Valve Systems, Fifth Edition, October 

2005, also available as ISO 10417: 2004, 

(Identical) Petroleum and natural gas 

industries—Subsurface safety valve 

systems—Design, installation, operation 

and redress; incorporated by reference 

at §§ 250.801 and 250.804; 

(56) API RP 14C, Recommended 

Practice for Analysis, Design, 

Installation, and Testing of Basic 

Surface Safety Systems for Offshore 

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, 

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2006; also available as ISO 10432:2004; 

incorporated by reference at § 250.806; 

(74) ANSI/API Spec. 17J, 

Specification for Unbonded Flexible 

Pipe, Third Edition, July 2008; Effective 

Date: January 1, 2009, Contains API 

Monogram Annex as Part of U.S. 

National Adoption; ISO 13628–2:2006 

(Identical), Petroleum and natural gas 

industries—Design and operation of 

subsea production systems—Part 2: 

Unbonded flexible pipe systems for 

subsea and marine application; 

incorporated by reference at §§ 250.803, 

250.1002, and 250.1007; 

(75) API Standard 2551, Measurement 

and Calibration of Horizontal Tanks, 

First Edition, 1965; reaffirmed March 

2002; incorporated by reference at 

§ 250.1202; 

(76) API Standard 2552, USA 

Standard Method for Measurement and 

Calibration of Spheres and Spheroids, 

First Edition, 1966; reaffirmed, October 

2007; incorporated by reference at 

§ 250.1202; 

(77) API Standard 2555, Method for 

Liquid Calibration of Tanks, First 

Edition, September 1966; reaffirmed 

March 2002; incorporated by reference 

at § 250.1202. 

(78) API RP 90, Annular Casing 

Pressure Management for Offshore 

Wells, First Edition, August 2006, 

incorporated by reference at § 250.518. 

(79) API RP 65–Part 2, Isolating 

Potential Flow Zones During Well 

Construction; First Edition, May 2010; 

incorporated by reference at § 250.415. 

(80) API RP 75, Recommended 

Practice for Development of a Safety and 

Environmental Management Program for 

Offshore Operations and Facilities, 

Third Edition, May 2004, Reaffirmed 

May 2008; incorporated by reference at 

§§ 250.1900, 250.1902, 250.1903, 

250.1909, 250.1920. 

(i) American Society for Testing and 

Materials (ASTM), ASTM Standards, 

100 Bar Harbor Drive, P. O. Box C700, 

West Conshohocken, PA 19428–2959; 

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 meet 

statutory and regulatory requirements, are safe and protect the environment, and result in diligent exploration, development, and production on OCS leases. To support the unproved and proved reserve 

estimation, resource assessment, and fair market value determinations. To allow BSEE to rapidly assess damage and project any disruption of oil and gas production from the OCS after a major natural 

occurrence. 

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30 CFR subpart, title and/or BSEE Form 

(OMB Control No.) Reasons for collecting information and how used 

(2) Subpart B, Exploration and Development and Production Plans 

(1010–0151).

To inform BSEE, States, and the public of planned exploration, development, and production operations on the OCS. To ensure that operations on the OCS are planned to comply with statutory and regulatory requirements, will be safe and protect the human, marine, and 

coastal environment, and will result in diligent exploration, development, and production of leases. 

(3) Subpart C, Pollution Prevention and Control (1010–0057) ................ To inform BSEE of measures to be taken to prevent water pollution. To 

ensure that appropriate measures are taken to prevent water pollution. 

(4) Subpart D, Oil and Gas and Drilling 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-completion 

operations 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 during 

well-workover operations on the OCS. To ensure that well-workover 

operations are safe and protect the human, marine, and coastal environment. 

(7) Subpart H, Oil and Gas Production Safety Systems (1010–0059) .... To inform BSEE of the equipment and procedures to be used during 

production operations on the OCS. To ensure that production operations are safe and protect the human, marine, and coastal environment. 

(8) Subpart I, Platforms and Structures (1010–0149) .............................. To provide BSEE with information regarding the design, fabrication, 

and installation of platforms on the OCS. To ensure the structural integrity of platforms installed on the OCS. 

(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 the 

OCS. 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 unitization 

prevents waste, conserves natural resources, and protects correlative rights. 

(13) Subpart N, Remedies and Penalties ................................................ The requirements in subpart N are exempt from the Paperwork Reduction Act of 1995 according to 5 CFR 1320.4. 

(14) Subpart O, Well Control and Production Safety Training (1010– 

0128).

To inform BSEE of training program curricula, course schedules, and 

attendance. To ensure that training programs are technically accurate and sufficient to meet safety and environmental requirements, 

and that workers are properly trained to operate on the OCS. 

(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; protect 

the 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 comply with regulatory 

requirements and approvals. To ensure that site clearance and platform or pipeline removal are properly performed to protect marine life 

and the environment and do not conflict with other users of the OCS. 

(17) Subpart S, Safety and 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 assure 

safety and environmental protection while conducting OCS operations (including those operations conducted by contractor and subcontractor personnel). The information collected is the form to gather 

the raw Performance Measures Data relating to risk and number of 

accidents, injuries, and oil spills during OCS activities. 

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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 postapproval monitoring? 

The Regional Supervisor may direct 

you to conduct monitoring programs. 

You must retain copies of all monitoring 

data obtained or derived from your 

monitoring programs and make them 

available to BSEE upon request. The 

Regional Supervisor may require you to: 

(a) Monitoring plans. Submit 

monitoring plans for approval before 

you begin work; and 

(b) Monitoring reports. Prepare and 

submit reports that summarize and 

analyze data and information obtained 

or derived from your monitoring 

programs. The Regional Supervisor will 

specify requirements for preparing and 

submitting these reports. 

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 collect 

treated-produced water, treatedproduced sand, or liquids from drip 

pans and deck drains and as a final trap 

for hydrocarbon liquids in the event of 

equipment upsets. Improperly designed, 

operated, or maintained sump piles 

which do not prevent the discharge of 

oil into offshore waters shall be replaced 

or repaired. 

(5) On artificial islands, all vessels 

containing hydrocarbons shall be placed 

inside an impervious berm or otherwise 

protected to contain spills. Drainage 

shall be directed away from the drilling 

rig to a sump. Drains and sumps shall 

be constructed to prevent seepage. 

(6) Disposal of equipment, cables, 

chains, containers, or other materials 

into offshore waters is prohibited. 

(c) Materials, equipment, tools, 

containers, and other items used in the 

Outer Continental Shelf (OCS) which 

are of such shape or configuration that 

they are likely to snag or damage fishing 

devices shall be handled and marked as 

follows: 

(1) All loose material, small tools, and 

other small objects shall be kept in a 

suitable storage area or a marked 

container when not in use and in a 

marked container before transport over 

offshore waters; 

(2) All cable, chain, or wire segments 

shall be recovered after use and securely 

stored until suitable disposal is 

accomplished; 

(3) Skid-mounted equipment, portable 

containers, spools or reels, and drums 

shall be marked with the owner’s name 

prior to use or transport over offshore 

waters; and 

(4) All markings must clearly identify 

the owner and must be durable enough 

to resist the effects of the environmental 

conditions to which they may be 

exposed. 

(d) Any of the items described in 

paragraph (c) of this section that are lost 

overboard shall be recorded on the 

facility’s daily operations report, as 

appropriate, and reported to the District 

Manager. 

§ 250.301 Inspection of facilities. 

Drilling and production facilities shall 

be inspected daily or at intervals 

approved or prescribed by the District 

Manager to determine if pollution is 

occurring. Necessary maintenance or 

repairs shall be made immediately. 

Records of such inspections and repairs 

shall be maintained at the facility or at 

a nearby manned facility for 2 years. 

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 at 

least 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 a 

technical classification society; an APIlicensed manufacturing, inspection, or 

certification firm; or a licensed 

professional engineering firm capable of 

providing the verifications required 

under this part. The independent third 

party must not be the original 

equipment manufacturer (OEM). 

(2) You must: 

(i) Include evidence that the firm you 

are using is reputable, the firm or its 

employees hold appropriate licenses to 

perform the verification in the 

appropriate jurisdiction, the firm carries 

industry-standard levels of professional 

liability insurance, and the firm has no 

record of violations of applicable law. 

(ii) Ensure that an official 

representative of BSEE will have access 

to the location to witness any testing or 

inspections, and verify information 

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submitted to BSEE. Prior to any shearing 

ram tests or inspections, you must 

notify the District Manager at least 24 

hours in advance. 

§ 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 the 

planned 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 casing 

types. 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 yield. 

(b) You must ensure proper 

installation of casing or liner in the 

subsea wellhead or liner hanger. 

(1) You must ensure that the latching 

mechanisms or lock down mechanisms 

are engaged upon installation of each 

casing string or liner. 

(2) You must perform a pressure test 

on the casing seal assembly to ensure 

proper installation of casing or liner. 

You must perform this test for the 

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intermediate and production casing 

strings or liner. 

(3) You must submit for approval with 

your APD, test procedures and criteria 

for a successful test. 

(4) You must document all your test 

results and make them available to 

BSEE upon request. 

(c) You must perform a negative 

pressure test on all wells to ensure 

proper casing installation. You must 

perform this test for the intermediate 

and production casing strings. 

(1) You must submit for approval with 

your APD, test procedures and criteria 

for a successful test. 

(2) You must document all your test 

results and make them available to 

BSEE upon request. 

§ 250.424 What are the requirements for 

prolonged drilling operations? 

If wellbore operations continue for 

more than 30 days within a casing string 

run to the surface: 

(a) You must stop drilling operations 

as soon as practicable, and evaluate the 

effects of the prolonged operations on 

continued drilling operations and the 

life of the well. At a minimum, you 

must: 

(1) Caliper or pressure test the casing; 

and 

(2) Report the results of your 

evaluation to the District Manager and 

obtain approval of those results before 

resuming operations. 

(b) If casing integrity has deteriorated 

to a level below minimum safety factors, 

you must: 

(1) Repair the casing or run another 

casing string; and 

(2) Obtain approval from the District 

Manager before you begin repairs. 

§ 250.425 What are the requirements for 

pressure testing liners? 

(a) You must test each drilling liner 

(and liner-lap) to a pressure at least 

equal to the anticipated pressure to 

which the liner will be subjected during 

the formation pressure-integrity test 

below that liner shoe, or subsequent 

liner shoes if set. The District Manager 

may approve or require other liner test 

pressures. 

(b) You must test each production 

liner (and liner-lap) to a minimum of 

500 psi above the formation fracture 

pressure at the casing shoe into which 

the liner is lapped. 

(c) You may not resume drilling or 

other down-hole operations until you 

obtain a satisfactory pressure test. If the 

pressure declines more than 10 percent 

in a 30-minute test or if there is another 

indication of a leak, you must recement, repair the liner, or run 

additional casing/liner to provide a 

proper seal. 

§ 250.426 What are the recordkeeping 

requirements for casing and liner pressure 

tests? 

You must record the time, date, and 

results of each pressure test in the 

driller’s report maintained under 

standard industry practice. In addition, 

you must record each test on a pressure 

chart and have your onsite 

representative sign and date the test as 

being correct. 

§ 250.427 What are the requirements for 

pressure integrity tests? 

You must conduct a pressure integrity 

test below the surface casing or liner 

and all intermediate casings or liners. 

The District Manager may require you to 

run a pressure-integrity test at the 

conductor casing shoe if warranted by 

local geologic conditions or the planned 

casing setting depth. You must conduct 

each pressure integrity test after drilling 

at least 10 feet but no more than 50 feet 

of new hole below the casing shoe. You 

must test to either the formation leak-off 

pressure or to an equivalent drilling 

fluid weight if identified in an approved 

APD. 

(a) You must use the pressure 

integrity test and related hole-behavior 

observations, such as pore-pressure test 

results, gas-cut drilling fluid, and well 

kicks to adjust the drilling fluid program 

and the setting depth of the next casing 

string. You must record all test results 

and hole-behavior observations made 

during the course of drilling related to 

formation integrity and pore pressure in 

the driller’s report. 

(b) While drilling, you must maintain 

the safe drilling margin identified in the 

approved APD. When you cannot 

maintain this safe margin, you must 

suspend drilling operations and remedy 

the situation. 

§ 250.428 What must I do in certain 

cementing and casing situations? 

The table in this section describes 

actions that lessees must take when 

certain situations occur during casing 

and cementing activities. 

If you encounter the following situation: Then you must . . . 

(a) Have unexpected formation pressures or conditions that warrant revising your casing design, 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 squeeze 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 demonstrates the absence of shallow hydrocarbons or hazards. This information must include logging and drilling fluid-monitoring from wells 

previously drilled within 500 feet of the proposed well path down to 

the next casing point. 

(h) Need to use less than required cement 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 sealing 

element, diverter valves, and divertercontrol systems and control stations. 

You must also flow-test the vent lines. 

(a) For drilling operations with a 

surface wellhead configuration, you 

must actuate the diverter system at least 

once every 24-hour period after the 

initial test. After you have nippled up 

on conductor casing, you must pressuretest the diverter-sealing element and 

diverter valves to a minimum of 200 psi. 

While the diverter is installed, you must 

conduct subsequent pressure tests 

within 7 days after the previous test. 

(b) For floating drilling operations 

with a subsea BOP stack, you must 

actuate the diverter system within 7 

days after the previous actuation. 

(c) You must alternate actuations and 

tests between control stations. 

§ 250.434 What are the recordkeeping 

requirements for diverter actuations and 

tests? 

You must record the time, date, and 

results of all diverter actuations and 

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 

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overrides or other devices to ensure 

capability of hydraulic operations if rig 

air is lost. 

(d) In addition to the stack and 

accumulator system, you must install 

the associated BOP systems and 

equipment required by the regulations 

in this subpart. 

§ 250.442 What are the requirements for a 

subsea BOP system? 

When you drill with a subsea BOP 

system, you must install the BOP system 

before drilling below the surface casing. 

The District Manager may require you to 

install a subsea BOP system before 

drilling below the conductor casing if 

proposed casing setting depths or local 

geology indicate the need. The table in 

this paragraph outlines your 

requirements. 

When drilling with a subsea BOP system, you must: Additional requirements 

(a) Have at least four remote-controlled, hydraulically operated BOPs .. You must have at least one annular BOP, two BOPs equipped with 

pipe rams, and one BOP equipped with blind-shear rams. The blindshear rams must be capable of shearing any drill pipe in the hole 

under maximum anticipated surface pressures. 

(b) Have an operable dual-pod control system to ensure proper and 

independent operation of the BOP system.

(c) Have an accumulator system to provide fast closure of the BOP 

components and to operate all critical functions in case of a loss of 

the power fluid connection to the surface.

The accumulator system must meet or exceed the provisions of Section 13.3, Accumulator Volumetric Capacity, in API RP 53, Recommended Practices for Blowout Prevention Equipment Systems for 

Drilling Wells (as incorporated by reference in § 250.198). The District Manager may approve a suitable alternate method. 

(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 ensure 

that 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 LMRP 

closes the shear rams. This is considered a ‘‘rapid discharge’’ system. 

(2) Deadman System means a safety system that is designed to automatically close the wellbore in the event of a simultaneous absence 

of hydraulic supply and signal transmission capacity in both subsea 

control pods. This is considered a ‘‘rapid discharge’’ system. 

(3) You may also have an acoustic system. 

(g) Have operational or physical 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 prevent 

accidental disconnection of these components) and minimum knowledge requirements for personnel authorized to operate and maintain 

BOP components. 

(j) Establish minimum requirements for personnel 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 that the 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 BOP 

system, you must conduct a lowpressure and a high-pressure test for 

each BOP component. You must 

conduct the low-pressure test before the 

high-pressure test. Each individual 

pressure test must hold pressure long 

enough to demonstrate that the tested 

component(s) holds the required 

pressure. Required test pressures are as 

follows: 

(a) Low-pressure test. All low-pressure 

tests must be between 200 and 300 psi. 

Any initial pressure above 300 psi must 

be bled back to a pressure between 200 

and 300 psi before starting the test. If 

the initial pressure exceeds 500 psi, you 

must bleed back to zero and reinitiate 

the test. 

(b) High-pressure test for ram-type 

BOPs, the choke manifold, and other 

BOP components. The high-pressure 

test must equal the rated working 

pressure of the equipment or be 500 psi 

greater than your calculated maximum 

anticipated surface pressure (MASP) for 

the applicable section of hole. Before 

you may test BOP equipment to the 

MASP plus 500 psi, the District 

Manager must have approved those test 

pressures in your APD. 

(c) High pressure test for annular-type 

BOPs. The high pressure test must equal 

70 percent of the rated working pressure 

of the equipment or to a pressure 

approved in your APD. 

(d) Duration of pressure test. Each test 

must hold the required pressure for 5 

minutes. However, for surface BOP 

systems and surface equipment of a 

subsea BOP system, a 3-minute test 

duration is acceptable if you record your 

test pressures on the outermost half of 

a 4-hour chart, on a 1-hour chart, or on 

a digital recorder. If the equipment does 

not hold the required pressure during a 

test, you must correct the problem and 

retest the affected component(s). 

§ 250.449 What additional BOP testing 

requirements must I meet? 

You must meet the following 

additional BOP testing requirements: 

(a) Use water to test a surface BOP 

system; 

(b) Stump test a subsea BOP system 

before installation. You must use water 

to conduct this test. You may use 

drilling fluids to conduct subsequent 

tests of a subsea BOP system; 

(c) Alternate tests between control 

stations and pods; 

(d) Pressure test the blind or blindshear ram BOP during stump tests and 

at all casing points; 

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(e) The interval between any blind or 

blind-shear ram BOP pressure tests may 

not exceed 30 days; 

(f) Pressure test variable bore-pipe 

ram BOPs against the largest and 

smallest sizes of pipe in use, excluding 

drill collars and bottom-hole tools; 

(g) Pressure test affected BOP 

components following the 

disconnection or repair of any wellpressure containment seal in the 

wellhead or BOP stack assembly; 

(h) Function test annular and ram 

BOPs every 7 days between pressure 

tests; 

(i) Actuate safety valves assembled 

with proper casing connections before 

running casing; 

(j) Test all ROV intervention functions 

on your subsea BOP stack during the 

stump test. You must also test at least 

one set of rams during the initial test on 

the seafloor. You must submit test 

procedures with your APD or APM for 

District Manager approval. You must: 

(1) ensure that the ROV hot stabs are 

function tested and are capable of 

actuating, at a minimum, one set of pipe 

rams and one set of blind-shear rams 

and unlatching the LMRP; and 

(2) document all your test results and 

make them available to BSEE upon 

request; 

(k) Function test autoshear and 

deadman systems on your subsea BOP 

stack during the stump test. You must 

also test the deadman system during the 

initial test on the seafloor. 

(1) You must submit test procedures 

with your APD or APM for District 

Manager approval. 

(2) You must document all your test 

results and make them available to 

BSEE upon request. 

§ 250.450 What are the recordkeeping 

requirements for BOP tests? 

You must record the time, date, and 

results of all pressure tests, actuations, 

and inspections of the BOP system, 

system components, and marine riser in 

the driller’s report. In addition, you 

must: 

(a) Record BOP test pressures on 

pressure charts; 

(b) Require your onsite representative 

to sign and date BOP test charts and 

reports as correct; 

(c) Document the sequential order of 

BOP and auxiliary equipment testing 

and the pressure and duration of each 

test. For subsea BOP systems, you must 

also record the closing times for annular 

and ram BOPs. You may reference a 

BOP test plan if it is available at the 

facility; 

(d) Identify the control station and 

pod used during the test; 

(e) Identify any problems or 

irregularities observed during BOP 

system testing and record actions taken 

to remedy the problems or irregularities; 

and 

(f) Retain all records, including 

pressure charts, driller’s report, and 

referenced documents pertaining to BOP 

tests, actuations, and inspections at the 

facility for the duration of drilling. 

§ 250.451 What must I do in certain 

situations involving BOP equipment or 

systems? 

The table in this section describes 

actions that lessees must take when 

certain situations occur with BOP 

systems during drilling activities. 

If you encounter the following situation: Then you must . . . 

(a) BOP equipment does not hold the required pressure during a test, 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 ventilation 

system and gas monitors. Drilling fluidhandling areas must have the following 

safety equipment: 

(a) A ventilation system capable of 

replacing the air once every 5 minutes 

or 1.0 cubic feet of air-volume flow per 

minute, per square foot of area, 

whichever is greater. In addition: 

(1) If natural means provide adequate 

ventilation, then a mechanical 

ventilation system is not necessary; 

(2) If a mechanical system does not 

run continuously, then it must activate 

when gas detectors indicate the 

presence of 1 percent or more of 

combustible gas by volume; and 

(3) If discharges from a mechanical 

ventilation system may be hazardous, 

then you must maintain the drilling 

fluid-handling area at a negative 

pressure. You must protect the negative 

pressure area by using at least one of the 

following: a pressure-sensitive alarm, 

open-door alarms on each access to the 

area, automatic door-closing devices, air 

locks, or other devices approved by the 

District Manager; 

(b) Gas detectors and alarms except in 

open areas where adequate ventilation 

is provided by natural means. You must 

test and recalibrate gas detectors 

quarterly. No more than 90 days may 

elapse between tests; 

(c) Explosion-proof or pressurized 

electrical equipment to prevent the 

ignition of explosive gases. Where you 

use air for pressuring equipment, you 

must locate the air intake outside of and 

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as far as practicable from hazardous 

areas; and 

(d) Alarms that activate when the 

mechanical ventilation system fails. 

Other Drilling Requirements 

§ 250.460 What are the requirements for 

conducting a well test? 

(a) If you intend to conduct a well 

test, you must include your projected 

plans for the test with your APD (form 

BSEE–0123) or in an Application for 

Permit to Modify (APM) (form BSEE– 

0124). Your plans must include at least 

the following information: 

(1) Estimated flowing and shut-in 

tubing pressures; 

(2) Estimated flow rates and 

cumulative volumes; 

(3) Time duration of flow, buildup, 

and drawdown periods; 

(4) Description and rating of surface 

and subsurface test equipment; 

(5) Schematic drawing, showing the 

layout of test equipment; 

(6) Description of safety equipment, 

including gas detectors and fire-fighting 

equipment; 

(7) Proposed methods to handle or 

transport produced fluids; and 

(8) Description of the test procedures. 

(b) You must give the District 

Manager at least 24-hours notice before 

starting a well test. 

§ 250.461 What are the requirements for 

directional and inclination surveys? 

For this subpart, BSEE classifies a 

well as vertical if the calculated average 

of inclination readings does not exceed 

3 degrees from the vertical. 

(a) Survey requirements for a vertical 

well. (1) You must conduct inclination 

surveys on each vertical well and record 

the results. Survey intervals may not 

exceed 1,000 feet during the normal 

course of drilling; 

(2) You must also conduct a 

directional survey that provides both 

inclination and azimuth, and digitally 

record the results in electronic format: 

(i) Within 500 feet of setting surface 

or intermediate casing; 

(ii) Within 500 feet of setting any 

liner; and 

(iii) When you reach total depth. 

(b) Survey requirements for 

directional well. You must conduct 

directional surveys on each directional 

well and digitally record the results. 

Surveys must give both inclination and 

azimuth at intervals not to exceed 500 

feet during the normal course of 

drilling. Intervals during angle-changing 

portions of the hole may not exceed 100 

feet. 

(c) Measurement while drilling. You 

may use measurement-while-drilling 

technology if it meets the requirements 

of this section. 

(d) Composite survey requirements. 

(1) Your composite directional survey 

must show the interval from the bottom 

of the conductor casing to total depth. 

In the absence of conductor casing, the 

survey must show the interval from the 

bottom of the drive or structural casing 

to total depth; and 

(2) You must correct all surveys to 

Universal-Transverse-Mercator-Gridnorth or Lambert-Grid-north after 

making the magnetic-to-true-north 

correction. Surveys must show the 

magnetic and grid corrections used and 

include a listing of the directionally 

computed inclinations and azimuths. 

(e) If you drill within 500 feet of an 

adjacent lease, the Regional Supervisor 

may require you to furnish a copy of the 

well’s directional survey to the affected 

leaseholder. This could occur when the 

adjoining leaseholder requests a copy of 

the survey for the protection of 

correlative rights. 

§ 250.462 What are the requirements for 

well-control drills? 

You must conduct a weekly wellcontrol drill with each drilling crew. 

Your drill must familiarize the crew 

with its roles and functions so that all 

crew members can perform their duties 

promptly and efficiently. 

(a) Well-control drill plan. You must 

prepare a well control drill plan for each 

well. Your plan must outline the 

assignments for each crew member and 

establish times to complete each portion 

of the drill. You must post a copy of the 

well control drill plan on the rig floor 

or bulletin board. 

(b) Timing of drills. You must conduct 

each drill during a period of activity 

that minimizes the risk to drilling 

operations. The timing of your drills 

must cover a range of different 

operations, including drilling with a 

diverter, on-bottom drilling, and 

tripping. 

(c) Recordkeeping requirements. For 

each drill, you must record the 

following in the driller’s report: 

(1) The time to be ready to close the 

diverter or BOP system; and 

(2) The total time to complete the 

entire drill. 

(d) BSEE ordered drill. A BSEE 

authorized representative may require 

you to conduct a well control drill 

during a BSEE inspection. The BSEE 

representative will consult with your 

onsite representative before requiring 

the drill. 

§ 250.463 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 you 

begin the intended operation. If you get an approval, you must submit form BSEE–0124 no later than the end of the 3rd business day 

following the oral approval. In all cases, or you must meet the additional requirements in paragraph (b) of this section. 

(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 after 

the 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 H2S area? You 

must: 

(1) Take all necessary and feasible 

precautions and measures to protect 

personnel from the toxic effects of H2S 

and to mitigate damage to property and 

the environment caused by H2S. You 

must follow the requirements of this 

section when conducting drilling, wellcompletion/well-workover, and 

production operations in zones with 

H2S present and when conducting 

operations in zones where the presence 

of H2S is unknown. You do not need to 

follow these requirements when 

operating in zones where the absence of 

H2S has been confirmed; and 

(2) Follow your approved contingency 

plan. 

(b) Definitions. Terms used in this 

section have the following meanings: 

Facility means a vessel, a structure, or 

an artificial island used for drilling, 

well-completion, well-workover, and/or 

production operations. 

H2S absent means: 

(1) Drilling, logging, coring, testing, or 

producing operations have confirmed 

the absence of H2S in concentrations 

that could potentially result in 

atmospheric concentrations of 20 ppm 

or more of H2S; or 

(2) Drilling in the surrounding areas 

and correlation of geological and 

seismic data with equivalent 

stratigraphic units have confirmed an 

absence of H2S throughout the area to be 

drilled. 

H2S present means that drilling, 

logging, coring, testing, or producing 

operations have confirmed the presence 

of H2S in concentrations and volumes 

that could potentially result in 

atmospheric concentrations of 20 ppm 

or more of H2S. 

H2S unknown means the designation 

of a zone or geologic formation where 

neither the presence nor absence of H2S 

has been confirmed. 

Well-control fluid means drilling mud 

and completion or workover fluid as 

appropriate to the particular operation 

being conducted. 

(c) Classifying an area for the 

presence of H2S. You must: 

(1) Request and obtain an approved 

classification for the area from the 

Regional Supervisor before you begin 

operations. Classifications are ‘‘H2S 

absent,’’ H2S present,’’ or ‘‘H2S 

unknown’’; 

(2) Submit your request with your 

application for permit to drill; 

(3) Support your request with 

available information such as geologic 

and geophysical data and correlations, 

well logs, formation tests, cores and 

analysis of formation fluids; and 

(4) Submit a request for 

reclassification of a zone when 

additional data indicate a different 

classification is needed. 

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(d) What do I do if conditions change? 

If you encounter H2S that could 

potentially result in atmospheric 

concentrations of 20 ppm or more in 

areas not previously classified as having 

H2S present, you must immediately 

notify BSEE and begin to follow 

requirements for areas with H2S present. 

(e) What are the requirements for 

conducting simultaneous operations? 

When conducting any combination of 

drilling, well-completion, wellworkover, and production operations 

simultaneously, you must follow the 

requirements in the section applicable 

to each individual operation. 

(f) Requirements for submitting an 

H2S Contingency Plan. Before you begin 

operations, you must submit an H2S 

Contingency Plan to the District 

Manager for approval. Do not begin 

operations before the District Manager 

approves your plan. You must keep a 

copy of the approved plan in the field, 

and you must follow the plan at all 

times. Your plan must include: 

(1) Safety procedures and rules that 

you will follow concerning equipment, 

drills, and smoking; 

(2) Training you provide for 

employees, contractors, and visitors; 

(3) Job position and title of the person 

responsible for the overall safety of 

personnel; 

(4) Other key positions, how these 

positions fit into your organization, and 

what the functions, duties, and 

responsibilities of those job positions 

are; 

(5) Actions that you will take when 

the concentration of H2S in the 

atmosphere reaches 20 ppm, who will 

be responsible for those actions, and a 

description of the audible and visual 

alarms to be activated; 

(6) Briefing areas where personnel 

will assemble during an H2S alert. You 

must have at least two briefing areas on 

each facility and use the briefing area 

that is upwind of the H2S source at any 

given time; 

(7) Criteria you will use to decide 

when to evacuate the facility and 

procedures you will use to safely 

evacuate all personnel from the facility 

by vessel, capsule, or lifeboat. If you use 

helicopters during H2S alerts, describe 

the types of H2S emergencies during 

which you consider the risk of 

helicopter activity to be acceptable and 

the precautions you will take during the 

flights; 

(8) Procedures you will use to safely 

position all vessels attendant to the 

facility. Indicate where you will locate 

the vessels with respect to wind 

direction. Include the distance from the 

facility and what procedures you will 

use to safely relocate the vessels in an 

emergency; 

(9) How you will provide protectivebreathing equipment for all personnel, 

including contractors and visitors; 

(10) The agencies and facilities you 

will notify in case of a release of H2S 

(that constitutes an emergency), how 

you will notify them, and their 

telephone numbers. Include all facilities 

that might be exposed to atmospheric 

concentrations of 20 ppm or more of 

H2S; 

(11) The medical personnel and 

facilities you will use if needed, their 

addresses, and telephone numbers; 

(12) H2S detector locations in 

production facilities producing gas 

containing 20 ppm or more of H2S. 

Include an ‘‘H2S Detector Location 

Drawing’’ showing: 

(i) All vessels, flare outlets, 

wellheads, and other equipment 

handling production containing H2S; 

(ii) Approximate maximum 

concentration of H2S in the gas stream; 

and 

(iii) Location of all H2S sensors 

included in your contingency plan; 

(13) Operational conditions when you 

expect to flare gas containing H2S 

including the estimated maximum gas 

flow rate, H2S concentration, and 

duration of flaring; 

(14) Your assessment of the risks to 

personnel during flaring and what 

precautionary measures you will take; 

(15) Primary and alternate methods to 

ignite the flare and procedures for 

sustaining ignition and monitoring the 

status of the flare (i.e., ignited or 

extinguished); 

(16) Procedures to shut off the gas to 

the flare in the event the flare is 

extinguished; 

(17) Portable or fixed sulphur dioxide 

(SO2)-detection system(s) you will use 

to determine SO2 concentration and 

exposure hazard when H2S is burned; 

(18) Increased monitoring and 

warning procedures you will take when 

the SO2 concentration in the atmosphere 

reaches 2 ppm; 

(19) Personnel protection measures or 

evacuation procedures you will initiate 

when the SO2 concentration in the 

atmosphere reaches 5 ppm; 

(20) Engineering controls to protect 

personnel from SO2; and 

(21) Any special equipment, 

procedures, or precautions you will use 

if you conduct any combination of 

drilling, well-completion, wellworkover, and production operations 

simultaneously. 

(g) Training program: (1) When and 

how often do employees need to be 

trained? All operators and contract 

personnel must complete an H2S 

training program to meet the 

requirements of this section: 

(i) Before beginning work at the 

facility; and 

(ii) Each year, within 1 year after 

completion of the previous class. 

(2) What training documentation do I 

need? For each individual working on 

the platform, either: 

(i) You must have documentation of 

this training at the facility where the 

individual is employed; or 

(ii) The employee must carry a 

training completion card. 

(3) What training do I need to give to 

visitors and employees previously 

trained on another facility? 

(i) Trained employees or contractors 

transferred from another facility must 

attend a supplemental briefing on your 

H2S equipment and procedures before 

beginning duty at your facility; 

(ii) Visitors who will remain on your 

facility more than 24 hours must receive 

the training required for employees by 

paragraph (g)(4) of this section; and 

(iii) Visitors who will depart before 

spending 24 hours on the facility are 

exempt from the training required for 

employees, but they must, upon arrival, 

complete a briefing that includes: 

(A) Information on the location and 

use of an assigned respirator; practice in 

donning and adjusting the assigned 

respirator; information on the safe 

briefing areas, alarm system, and 

hazards of H2S and SO2; and 

(B) Instructions on their 

responsibilities in the event of an H2S 

release. 

(4) What training must I provide to all 

other employees? You must train all 

individuals on your facility on the: 

(i) Hazards of H2S and of SO2 and the 

provisions for personnel safety 

contained in the H2S Contingency Plan; 

(ii) Proper use of safety equipment 

which the employee may be required to 

use; 

(iii) Location of protective breathing 

equipment, H2S detectors and alarms, 

ventilation equipment, briefing areas, 

warning systems, evacuation 

procedures, and the direction of 

prevailing winds; 

(iv) Restrictions and corrective 

measures concerning beards, spectacles, 

and contact lenses in conformance with 

ANSI Z88.2, American National 

Standard for Respiratory Protection (as 

specified in § 250.198); 

(v) Basic first-aid procedures 

applicable to victims of H2S exposure. 

During all drills and training sessions, 

you must address procedures for rescue 

and first aid for H2S victims; 

(vi) Location of: 

(A) The first-aid kit on the facility; 

(B) Resuscitators; and 

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(C) Litter or other device on the 

facility. 

(vii) Meaning of all warning signals. 

(5) Do I need to post safety 

information? You must prominently 

post safety information on the facility 

and on vessels serving the facility (i.e., 

basic first-aid, escape routes, 

instructions for use of life boats, etc.). 

(h) Drills. (1) When and how often do 

I need to conduct drills on H2S safety 

discussions on the facility? You must: 

(i) Conduct a drill for each person at 

the facility during normal duty hours at 

least once every 7-day period. The drills 

must consist of a dry-run performance 

of personnel activities related to 

assigned jobs. 

(ii) At a safety meeting or other 

meetings of all personnel, discuss drill 

performance, new H2S considerations at 

the facility, and other updated H2S 

information at least monthly. 

(2) What documentation do I need? 

You must keep records of attendance 

for: 

(i) Drilling, well-completion, and 

well-workover operations at the facility 

until operations are completed; and 

(ii) Production operations at the 

facility or at the nearest field office for 

1 year. 

(i) Visual and audible warning 

systems: (1) How must I install wind 

direction equipment? You must install 

wind-direction equipment in a location 

visible at all times to individuals on or 

in the immediate vicinity of the facility. 

(2) When do I need to display 

operational danger signs, display flags, 

or activate visual or audible alarms? 

(i) You must display warning signs at 

all times on facilities with wells capable 

of producing H2S and on facilities that 

process gas containing H2S in 

concentrations of 20 ppm or more. 

(ii) In addition to the signs, you must 

activate audible alarms and display flags 

or activate flashing red lights when 

atmospheric concentration of H2S 

reaches 20 ppm. 

(3) What are the requirements for 

signs? Each sign must be a highvisibility yellow color with black 

lettering as follows: 

Letter height Wording 

12 inches ................... Danger. 

Poisonous Gas. 

Hydrogen Sulfide. 

7 inches ..................... Do not approach if 

red flag is flying. 

(Use appropriate 

wording at right).

Do not approach if 

red lights are flashing. 

(4) May I use existing signs? You may 

use existing signs containing the words 

‘‘Danger-Hydrogen Sulfide-H2S,’’ 

provided the words ‘‘Poisonous Gas. Do 

Not Approach if Red Flag is Flying’’ or 

‘‘Red Lights are Flashing’’ in lettering of 

a minimum of 7 inches in height are 

displayed on a sign immediately 

adjacent to the existing sign. 

(5) What are the requirements for 

flashing lights or flags? You must 

activate a sufficient number of lights or 

hoist a sufficient number of flags to be 

visible to vessels and aircraft. Each light 

must be of sufficient intensity to be seen 

by approaching vessels or aircraft any 

time it is activated (day or night). Each 

flag must be red, rectangular, a 

minimum width of 3 feet, and a 

minimum height of 2 feet. 

(6) What is an audible warning 

system? An audible warning system is a 

public address system or siren, horn, or 

other similar warning device with a 

unique sound used only for H2S. 

(7) Are there any other requirements 

for visual or audible warning devices? 

Yes, you must: 

(i) Illuminate all signs and flags at 

night and under conditions of poor 

visibility; and 

(ii) Use warning devices that are 

suitable for the electrical classification 

of the area. 

(8) What actions must I take when the 

alarms are activated? When the warning 

devices are activated, the designated 

responsible persons must inform 

personnel of the level of danger and 

issue instructions on the initiation of 

appropriate protective measures. 

(j) H2S-detection and H2S monitoring 

equipment: (1) What are the 

requirements for an H2S detection 

system? An H2S detection system must: 

(i) Be capable of sensing a minimum 

of 10 ppm of H2S in the atmosphere; 

and 

(ii) Activate audible and visual alarms 

when the concentration of H2S in the 

atmosphere reaches 20 ppm. 

(2) Where must I have sensors for 

drilling, well-completion, and wellworkover operations? You must locate 

sensors at the: 

(i) Bell nipple; 

(ii) Mud-return line receiver tank 

(possum belly); 

(iii) Pipe-trip tank; 

(iv) Shale shaker; 

(v) Well-control fluid pit area; 

(vi) Driller’s station; 

(vii) Living quarters; and 

(viii) All other areas where H2S may 

accumulate. 

(3) Do I need mud sensors? The 

District Manager may require mud 

sensors in the possum belly in cases 

where the ambient air sensors in the 

mud-return system do not consistently 

detect the presence of H2S. 

(4) How often must I observe the 

sensors? During drilling, wellcompletion and well-workover 

operations, you must continuously 

observe the H2S levels indicated by the 

monitors in the work areas during the 

following operations: 

(i) When you pull a wet string of drill 

pipe or workover string; 

(ii) When circulating bottoms-up after 

a drilling break; 

(iii) During cementing operations; 

(iv) During logging operations; and 

(v) When circulating to condition 

mud or other well-control fluid. 

(5) Where must I have sensors for 

production operations? On a platform 

where gas containing H2S of 20 ppm or 

greater is produced, processed, or 

otherwise handled: 

(i) You must have a sensor in rooms, 

buildings, deck areas, or low-laying 

deck areas not otherwise covered by 

paragraph (j)(2) of this section, where 

atmospheric concentrations of H2S 

could reach 20 ppm or more. You must 

have at least one sensor per 400 square 

feet of deck area or fractional part of 400 

square feet; 

(ii) You must have a sensor in 

buildings where personnel have their 

living quarters; 

(iii) You must have a sensor within 10 

feet of each vessel, compressor, 

wellhead, manifold, or pump, which 

could release enough H2S to result in 

atmospheric concentrations of 20 ppm 

at a distance of 10 feet from the 

component; 

(iv) You may use one sensor to detect 

H2S around multiple pieces of 

equipment, provided the sensor is 

located no more than 10 feet from each 

piece, except that you need to use at 

least two sensors to monitor 

compressors exceeding 50 horsepower; 

(v) You do not need to have sensors 

near wells that are shut in at the master 

valve and sealed closed; 

(vi) When you determine where to 

place sensors, you must consider: 

(A) The location of system fittings, 

flanges, valves, and other devices 

subject to leaks to the atmosphere; and 

(B) Design factors, such as the type of 

decking and the location of fire walls; 

and 

(vii) The District Manager may require 

additional sensors or other monitoring 

capabilities, if warranted by site specific 

conditions. 

(6) How must I functionally test the 

H2S Detectors? (i) Personnel trained to 

calibrate the particular H2S detector 

equipment being used must test 

detectors by exposing them to a known 

concentration in the range of 10 to 30 

ppm of H2S. 

(ii) If the results of any functional test 

are not within 2 ppm or 10 percent, 

whichever is greater, of the applied 

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concentration, recalibrate the 

instrument. 

(7) How often must I test my 

detectors? (i) When conducting drilling, 

drill stem testing, well-completion, or 

well-workover operations in areas 

classified as H2S present or H2S 

unknown, test all detectors at least once 

every 24 hours. When drilling, begin 

functional testing before the bit is 1,500 

feet (vertically) above the potential H2S 

zone. 

(ii) When conducting production 

operations, test all detectors at least 

every 14 days between tests. 

(iii) If equipment requires calibration 

as a result of two consecutive functional 

tests, the District Manager may require 

that H2S-detection and H2S-monitoring 

equipment be functionally tested and 

calibrated more frequently. 

(8) What documentation must I keep? 

(i) You must maintain records of testing 

and calibrations (in the drilling or 

production operations report, as 

applicable) at the facility to show the 

present status and history of each 

device, including dates and details 

concerning: 

(A) Installation; 

(B) Removal; 

(C) Inspection; 

(D) Repairs; 

(E) Adjustments; and 

(F) Reinstallation. 

(ii) Records must be available for 

inspection by BSEE personnel. 

(9) What are the requirements for 

nearby vessels? If vessels are stationed 

overnight alongside facilities in areas of 

H2S present or H2S unknown, you must 

equip vessels with an H2S-detection 

system that activates audible and visual 

alarms when the concentration of H2S in 

the atmosphere reaches 20 ppm. This 

requirement does not apply to vessels 

positioned upwind and at a safe 

distance from the facility in accordance 

with the positioning procedure 

described in the approved H2S 

Contingency Plan. 

(10) What are the requirements for 

nearby facilities? The District Manager 

may require you to equip nearby 

facilities with portable or fixed H2S 

detector(s) and to test and calibrate 

those detectors. To invoke this 

requirement, the District Manager will 

consider dispersion modeling results 

from a possible release to determine if 

20 ppm H2S concentration levels could 

be exceeded at nearby facilities. 

(11) What must I do to protect against 

SO2 if I burn gas containing H2S? You 

must: 

(i) Monitor the SO2concentration in 

the air with portable or strategically 

placed fixed devices capable of 

detecting a minimum of 2 ppm of SO2; 

(ii) Take readings at least hourly and 

at any time personnel detect SO2 odor 

or nasal irritation; 

(iii) Implement the personnel 

protective measures specified in the H2S 

Contingency Plan if the SO2

concentration in the work area reaches 

2 ppm; and 

(iv) Calibrate devices every 3 months 

if you use fixed or portable electronic 

sensing devices to detect SO2. 

(12) May I use alternative measures? 

You may follow alternative measures 

instead of those in paragraph (j)(11) of 

this section if you propose and the 

Regional Supervisor approves the 

alternative measures. 

(13) What are the requirements for 

protective-breathing equipment? In an 

area classified as H2S present or H2S 

unknown, you must: 

(i) Provide all personnel, including 

contractors and visitors on a facility, 

with immediate access to self-contained 

pressure-demand-type respirators with 

hoseline capability and breathing time 

of at least 15 minutes. 

(ii) Design, select, use, and maintain 

respirators in conformance with ANSI 

Z88.2 (as specified in § 250.198). 

(iii) Make available at least two voicetransmission devices, which can be 

used while wearing a respirator, for use 

by designated personnel. 

(iv) Make spectacle kits available as 

needed. 

(v) Store protective-breathing 

equipment in a location that is quickly 

and easily accessible to all personnel. 

(vi) Label all breathing-air bottles as 

containing breathing-quality air for 

human use. 

(vii) Ensure that vessels attendant to 

facilities carry appropriate protectivebreathing equipment for each crew 

member. The District Manager may 

require additional protective-breathing 

equipment on certain vessels attendant 

to the facility. 

(viii) During H2S alerts, limit 

helicopter flights to and from facilities 

to the conditions specified in the H2S 

Contingency Plan. During authorized 

flights, the flight crew and passengers 

must use pressure-demand-type 

respirators. You must train all members 

of flight crews in the use of the 

particular type(s) of respirator 

equipment made available. 

(ix) As appropriate to the particular 

operation(s), (production, drilling, wellcompletion or well-workover 

operations, or any combination of 

them), provide a system of breathing-air 

manifolds, hoses, and masks at the 

facility and the briefing areas. You must 

provide a cascade air-bottle system for 

the breathing-air manifolds to refill 

individual protective-breathing 

apparatus bottles. The cascade air-bottle 

system may be recharged by a highpressure compressor suitable for 

providing breathing-quality air, 

provided the compressor suction is 

located in an uncontaminated 

atmosphere. 

(k) Personnel safety equipment: (1) 

What additional personnel-safety 

equipment do I need? You must ensure 

that your facility has: 

(i) Portable H2S detectors capable of 

detecting a 10 ppm concentration of H2S 

in the air available for use by all 

personnel; 

(ii) Retrieval ropes with safety 

harnesses to retrieve incapacitated 

personnel from contaminated areas; 

(iii) Chalkboards and/or note pads for 

communication purposes located on the 

rig floor, shale-shaker area, the cementpump rooms, well-bay areas, production 

processing equipment area, gas 

compressor area, and pipeline-pump 

area; 

(iv) Bull horns and flashing lights; 

and 

(v) At least three resuscitators on 

manned facilities, and a number equal 

to the personnel on board, not to exceed 

three, on normally unmanned facilities, 

complete with face masks, oxygen 

bottles, and spare oxygen bottles. 

(2) What are the requirements for 

ventilation equipment? You must: 

(i) Use only explosion-proof 

ventilation devices; 

(ii) Install ventilation devices in areas 

where H2S or SO2 may accumulate; and 

(iii) Provide movable ventilation 

devices in work areas. The movable 

ventilation devices must be 

multidirectional and capable of 

dispersing H2S or SO2 vapors away from 

working personnel. 

(3) What other personnel safety 

equipment do I need? You must have 

the following equipment readily 

available on each facility: 

(i) A first-aid kit of appropriate size 

and content for the number of personnel 

on the facility; and 

(ii) At least one litter or an equivalent 

device. 

(l) Do I need to notify BSEE in the 

event of an H2S release? You must 

notify BSEE without delay in the event 

of a gas release which results in a 15- 

minute time-weighted average 

atmospheric concentration of H2S of 20 

ppm or more anywhere on the OCS 

facility. You must report these gas 

releases to the District Manager 

immediately by oral communication, 

with a written follow-up report within 

15 days, pursuant to §§ 250.188 through 

250.190. 

(m) Do I need to use special drilling, 

completion and workover fluids or 

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procedures? When working in an area 

classified as H2S present or H2S 

unknown: 

(1) You may use either water- or oilbase muds in accordance with 

§ 250.300(b)(1). 

(2) If you use water-base well-control 

fluids, and if ambient air sensors detect 

H2S, you must immediately conduct 

either the Garrett-Gas-Train test or a 

comparable test for soluble sulfides to 

confirm the presence of H2S. 

(3) If the concentration detected by air 

sensors in over 20 ppm, personnel 

conducting the tests must don 

protective-breathing equipment 

conforming to paragraph (j)(13) of this 

section. 

(4) You must maintain on the facility 

sufficient quantities of additives for the 

control of H2S, well-control fluid pH, 

and corrosion equipment. 

(i) Scavengers. You must have 

scavengers for control of H2S available 

on the facility. When H2S is detected, 

you must add scavengers as needed. 

You must suspend drilling until the 

scavenger is circulated throughout the 

system. 

(ii) Control pH. You must add 

additives for the control of pH to waterbase well-control fluids in sufficient 

quantities to maintain pH of at least 

10.0. 

(iii) Corrosion inhibitors. You must 

add additives to the well-control fluid 

system as needed for the control of 

corrosion. 

(5) You must degas well-control fluids 

containing H2S at the optimum location 

for the particular facility. You must 

collect the gases removed and burn 

them in a closed flare system 

conforming to paragraph (q)(6) of this 

section. 

(n) What must I do in the event of a 

kick? In the event of a kick, you must 

use one of the following alternatives to 

dispose of the well-influx fluids giving 

consideration to personnel safety, 

possible environmental damage, and 

possible facility well-equipment 

damage: 

(1) Contain the well-fluid influx by 

shutting in the well and pumping the 

fluids back into the formation. 

(2) Control the kick by using 

appropriate well-control techniques to 

prevent formation fracturing in an open 

hole within the pressure limits of the 

well equipment (drill pipe, work string, 

casing, wellhead, BOP system, and 

related equipment). The disposal of H2S 

and other gases must be through 

pressurized or atmospheric mudseparator equipment depending on 

volume, pressure and concentration of 

H2S. The equipment must be designed 

to recover well-control fluids and burn 

the gases separated from the wellcontrol fluid. The well-control fluid 

must be treated to neutralize H2S and 

restore and maintain the proper quality. 

(o) Well testing in a zone known to 

contain H2S. When testing a well in a 

zone with H2S present, you must do all 

of the following: 

(1) Before starting a well test, conduct 

safety meetings for all personnel who 

will be on the facility during the test. At 

the meetings, emphasize the use of 

protective-breathing equipment, first-aid 

procedures, and the Contingency Plan. 

Only competent personnel who are 

trained and are knowledgeable of the 

hazardous effects of H2S must be 

engaged in these tests. 

(2) Perform well testing with the 

minimum number of personnel in the 

immediate vicinity of the rig floor and 

with the appropriate test equipment to 

safely and adequately perform the test. 

During the test, you must continuously 

monitor H2S levels. 

(3) Not burn produced gases except 

through a flare which meets the 

requirements of paragraph (q)(6) of this 

section. Before flaring gas containing 

H2S, you must activate SO2 monitoring 

equipment in accordance with 

paragraph (j)(11) of this section. If you 

detect SO2 in excess of 2 ppm, you must 

implement the personnel protective 

measures in your H2S Contingency Plan, 

required by paragraph (f) of this section. 

You must also follow the requirements 

of § 250.1164. You must pipe gases from 

stored test fluids into the flare outlet 

and burn them. 

(4) Use downhole test tools and 

wellhead equipment suitable for H2S 

service. 

(5) Use tubulars suitable for H2S 

service. You must not use drill pipe for 

well testing without the prior approval 

of the District Manager. Water cushions 

must be thoroughly inhibited in order to 

prevent H2S attack on metals. You must 

flush the test string fluid treated for this 

purpose after completion of the test. 

(6) Use surface test units and related 

equipment that is designed for H2S 

service. 

(p) Metallurgical properties of 

equipment. When operating in a zone 

with H2S present, you must use 

equipment that is constructed of 

materials with metallurgical properties 

that resist or prevent sulfide stress 

cracking (also known as hydrogen 

embrittlement, stress corrosion cracking, 

or H2S embrittlement), chloride-stress 

cracking, hydrogen-induced cracking, 

and other failure modes. You must do 

all of the following: 

(1) Use tubulars and other equipment, 

casing, tubing, drill pipe, couplings, 

flanges, and related equipment that is 

designed for H2S service. 

(2) Use BOP system components, 

wellhead, pressure-control equipment, 

and related equipment exposed to H2Sbearing fluids in conformance with 

NACE Standard MR0175–03 (as 

specified in § 250.198). 

(3) Use temporary downhole wellsecurity devices such as retrievable 

packers and bridge plugs that are 

designed for H2S service. 

(4) When producing in zones bearing 

H2S, use equipment constructed of 

materials capable of resisting or 

preventing sulfide stress cracking. 

(5) Keep the use of welding to a 

minimum during the installation or 

modification of a production facility. 

Welding must be done in a manner that 

ensures resistance to sulfide stress 

cracking. 

(q) General requirements when 

operating in an H2S zone: (1) Coring 

operations. When you conduct coring 

operations in H2S-bearing zones, all 

personnel in the working area must 

wear protective-breathing equipment at 

least 10 stands in advance of retrieving 

the core barrel. Cores to be transported 

must be sealed and marked for the 

presence of H2S. 

(2) Logging operations. You must treat 

and condition well-control fluid in use 

for logging operations to minimize the 

effects of H2S on the logging equipment. 

(3) Stripping operations. Personnel 

must monitor displaced well-control 

fluid returns and wear protectivebreathing equipment in the working 

area when the atmospheric 

concentration of H2S reaches 20 ppm or 

if the well is under pressure. 

(4) Gas-cut well-control fluid or well 

kick from H2S-bearing zone. If you 

decide to circulate out a kick, personnel 

in the working area during bottoms-up 

and extended-kill operations must wear 

protective-breathing equipment. 

(5) Drill- and workover-string design 

and precautions. Drill- and workoverstrings must be designed consistent with 

the anticipated depth, conditions of the 

hole, and reservoir environment to be 

encountered. You must minimize 

exposure of the drill- or workover-string 

to high stresses as much as practical and 

consistent with well conditions. Proper 

handling techniques must be taken to 

minimize notching and stress 

concentrations. Precautions must be 

taken to minimize stresses caused by 

doglegs, improper stiffness ratios, 

improper torque, whip, abrasive wear 

on tool joints, and joint imbalance. 

(6) Flare system. The flare outlet must 

be of a diameter that allows easy 

nonrestricted flow of gas. You must 

locate flare line outlets on the downside 

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of the facility and as far from the facility 

as is feasible, taking into account the 

prevailing wind directions, the wake 

effects caused by the facility and 

adjacent structure(s), and the height of 

all such facilities and structures. You 

must equip the flare outlet with an 

automatic ignition system including a 

pilot-light gas source or an equivalent 

system. You must have alternate 

methods for igniting the flare. You must 

pipe to the flare system used for H2S all 

vents from production process 

equipment, tanks, relief valves, burst 

plates, and similar devices. 

(7) Corrosion mitigation. You must 

use effective means of monitoring and 

controlling corrosion caused by acid 

gases (H2S and CO2) in both the 

downhole and surface portions of a 

production system. You must take 

specific corrosion monitoring and 

mitigating measures in areas of 

unusually severe corrosion where 

accumulation of water and/or higher 

concentration of H2S exists. 

(8) Wireline lubricators. Lubricators 

which may be exposed to fluids 

containing H2S must be of H2S-resistant 

materials. 

(9) Fuel and/or instrument gas. You 

must not use gas containing H2S for 

instrument gas. You must not use gas 

containing H2S for fuel gas without the 

prior approval of the District Manager. 

(10) Sensing lines and devices. Metals 

used for sensing line and safety-control 

devices which are necessarily exposed 

to H2S-bearing fluids must be 

constructed of H2S-corrosion resistant 

materials or coated so as to resist H2S 

corrosion. 

(11) Elastomer seals. You must use 

H2S-resistant materials for all seals 

which may be exposed to fluids 

containing H2S. 

(12) Water disposal. If you dispose of 

produced water by means other than 

subsurface injection, you must submit to 

the District Manager an analysis of the 

anticipated H2S content of the water at 

the final treatment vessel and at the 

discharge point. The District Manager 

may require that the water be treated for 

removal of H2S. The District Manager 

may require the submittal of an updated 

analysis if the water disposal rate or the 

potential H2S content increases. 

(13) Deck drains. You must equip 

open deck drains with traps or similar 

devices to prevent the escape of H2S gas 

into the atmosphere. 

(14) Sealed voids. You must take 

precautions to eliminate sealed spaces 

in piping designs (e.g., slip-on flanges, 

reinforcing pads) which can be invaded 

by atomic hydrogen when H2S is 

present. 

Subpart E—Oil and Gas WellCompletion Operations 

§ 250.500 General requirements. 

Well-completion operations shall be 

conducted in a manner to protect 

against harm or damage to life 

(including fish and other aquatic life), 

property, natural resources of the OCS 

including any mineral deposits (in areas 

leased and not leased), the National 

security or defense, or the marine, 

coastal, or human environment. 

§ 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 moved 

shall also be equipped with a backpressure valve prior to removing the 

blowout preventer (BOP) system and 

installing the tree. 

§ 250.503 Emergency shutdown system. 

When well-completion operations are 

conducted on a platform where there are 

other hydrocarbon-producing wells or 

other hydrocarbon flow, an emergency 

shutdown system (ESD) manually 

controlled station shall be installed near 

the driller’s console or well-servicing 

unit operator’s work station. 

§ 250.504 Hydrogen sulfide. 

When a well-completion operation is 

conducted in zones known to contain 

hydrogen sulfide (H2S) or in zones 

where the presence of H2S is unknown 

(as defined in § 250.490 of this part), the 

lessee shall take appropriate precautions 

to protect life and property on the 

platform or completion unit, including, 

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. 

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§ 250.511 Traveling-block safety device. 

All units being used for wellcompletion operations that have both a 

traveling block and a crown block must 

be equipped with a safety device that is 

designed to prevent the traveling block 

from striking the crown block. The 

device must be checked for proper 

operation weekly and after each drillline slipping operation. The results of 

the operational check must be entered 

in the operations log. 

§ 250.512 Field well-completion rules. 

When geological and engineering 

information available in a field enables 

the District Manager to determine 

specific operating requirements, field 

well-completion rules may be 

established on the District Manager’s 

initiative or in response to a request 

from a lessee. Such rules may modify 

the specific requirements of this 

subpart. After field well-completion 

rules have been established, wellcompletion operations in the field shall 

be conducted in accordance with such 

rules and other requirements of this 

subpart. Field well-completion rules 

may be amended or canceled for cause 

at any time upon the initiative of the 

District Manager or upon the request of 

a lessee. 

§ 250.513 Approval and reporting of wellcompletion operations. 

(a) No well-completion operation may 

begin until the lessee receives written 

approval from the District Manager. If 

completion is planned and the data are 

available at the time you submit the 

Application for Permit to Drill and 

Supplemental APD Information Sheet 

(Forms BSEE–0123 and BSEE–0123S), 

you may request approval for a wellcompletion on those forms (see 

§§ 250.410 through 250.418 of this part). 

If the District Manager has not approved 

the completion or if the completion 

objective or plans have significantly 

changed, you must submit an 

Application for Permit to Modify (Form 

BSEE–0124) for approval of such 

operations. 

(b) You must submit the following 

with Form BSEE–0124 (or with Form 

BSEE–0123; Form BSEE–0123S): 

(1) A brief description of the wellcompletion procedures to be followed, a 

statement of the expected surface 

pressure, and type and weight of 

completion fluids; 

(2) A schematic drawing of the well 

showing the proposed producing 

zone(s) and the subsurface wellcompletion equipment to be used; 

(3) For multiple completions, a partial 

electric log showing the zones proposed 

for completion, if logs have not been 

previously submitted; 

(4) When the well-completion is in a 

zone known to contain H2S or a zone 

where the presence of H2S is unknown, 

information pursuant to § 250.490 of 

this part; and 

(5) Payment of the service fee listed in 

§ 250.125. 

(c) Within 30 days after completion, 

you must submit to the District Manager 

an End of Operations Report (Form 

BSEE–0125), including a schematic of 

the tubing and subsurface equipment. 

(d) You must submit public 

information copies of Form BSEE–0125 

according to § 250.186. 

§ 250.514 Well-control fluids, equipment, 

and operations. 

(a) Well-control fluids, equipment, 

and operations shall be designed, 

utilized, maintained, and/or tested as 

necessary to control the well in 

foreseeable conditions and 

circumstances, including subfreezing 

conditions. The well shall be 

continuously monitored during wellcompletion operations and shall not be 

left unattended at any time unless the 

well is shut in and secured. 

(b) The following well-control-fluid 

equipment shall be installed, 

maintained, and utilized: 

(1) A fill-up line above the uppermost 

BOP; 

(2) A well-control, fluid-volume 

measuring device for determining fluid 

volumes when filling the hole on trips; 

and 

(3) A recording mud-pit-level 

indicator to determine mud-pit-volume 

gains and losses. This indicator shall 

include both a visual and an audible 

warning device. 

(c) When coming out of the hole with 

drill pipe, the annulus shall be filled 

with well-control fluid before the 

change in such fluid level decreases the 

hydrostatic pressure 75 pounds per 

square inch (psi) or every five stands of 

drill pipe, whichever gives a lower 

decrease in hydrostatic pressure. The 

number of stands of drill pipe and drill 

collars that may be pulled prior to 

filling the hole and the equivalent wellcontrol fluid volume shall be calculated 

and posted near the operator’s station. A 

mechanical, volumetric, or electronic 

device for measuring the amount of 

well-control fluid required to fill the 

hole shall be utilized. 

§ 250.515 Blowout prevention equipment. 

(a) The BOP system and system 

components and related well-control 

equipment shall be designed, used, 

maintained, and tested in a manner 

necessary to assure well control in 

foreseeable conditions and 

circumstances, including subfreezing 

conditions. The working pressure rating 

of the BOP system and BOP system 

components shall exceed the expected 

surface pressure to which they may be 

subjected. If the expected surface 

pressure exceeds the rated working 

pressure of the annular preventer, the 

lessee shall submit with Form BSEE– 

0124 or Form BSEE–0123, as 

appropriate, a well-control procedure 

that indicates how the annular 

preventer will be utilized, and the 

pressure limitations that will be applied 

during each mode of pressure control. 

(b) The minimum BOP system for 

well-completion operations must meet 

the appropriate standards from the 

following table: 

When . . . The minimum BOP stack must include . . . 

(1) The expected pressure is less than 5,000 psi, Three BOPs consisting of an annular, one set of pipe rams, and one 

set of blind-shear rams. 

(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-completion 

operations. A wrench to fit the workstring safety valve shall be readily 

available. Proper connections shall be 

readily available for inserting valves in 

the work string. 

(e) The subsea BOP system for wellcompletions must meet the 

requirements in § 250.442 of this part. 

§ 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 may 

postpone a BOP test if you have wellcontrol problems. You must conduct the 

required BOP test as soon as possible 

(i.e., first trip out of the hole) after the 

problem has been remedied. You must 

record the reason for postponing any 

test in the driller’s report. 

(f) Weekly crew drills. You must 

conduct a weekly drill to familiarize all 

personnel engaged in well-completion 

operations with appropriate safety 

measures. 

(g) BOP inspections. (1) You must 

inspect your BOP system to ensure that 

the equipment functions properly. The 

BOP inspections must meet or exceed 

the provisions of Sections 17.10 and 

18.10, Inspections, described in API RP 

53, Recommended Practices for Blowout 

Prevention Equipment Systems for 

Drilling Wells (as incorporated by 

reference in § 250.198). You must 

document the procedures used, record 

the results, and make them available to 

BSEE upon request. You must maintain 

your records on the rig for 2 years or 

from the date of your last major 

inspection, whichever is longer. 

(2) You must visually inspect your 

BOP system and marine riser at least 

once each day if weather and sea 

conditions permit. You may use 

television cameras to inspect this 

equipment. The District Manager may 

approve alternate methods and 

frequencies to inspect a marine riser. 

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(h) BOP maintenance. You must 

maintain your BOP system to ensure 

that the equipment functions properly. 

The BOP maintenance must meet or 

exceed the provisions of Sections 17.11 

and 18.11, Maintenance; and Sections 

17.12 and 18.12, Quality Management, 

described in API RP 53, Recommended 

Practices for Blowout Prevention 

Equipment Systems for Drilling Wells 

(as incorporated by reference in 

§ 250.198). You must document the 

procedures used, record the results, and 

make available to BSEE upon request. 

You must maintain your records on the 

rig for 2 years or from the date of your 

last major inspection, whichever is 

longer. 

(i) BOP test records. You must record 

the time, date, and results of all pressure 

tests, actuations, crew drills, and 

inspections of the BOP system, system 

components, and marine riser in the 

driller’s report. In addition, you must: 

(1) Record BOP test pressures on 

pressure charts; 

(2) Have your onsite representative 

certify (sign and date) BOP test charts 

and reports as correct; 

(3) Document the sequential order of 

BOP and auxiliary equipment testing 

and the pressure and duration of each 

test. You may reference a BOP test plan 

if it is available at the facility; 

(4) Identify the control station or pod 

used during the test; 

(5) Identify any problems or 

irregularities observed during BOP 

system and equipment testing and 

record actions taken to remedy the 

problems or irregularities; 

(6) Retain all records including 

pressure charts, driller’s report, and 

referenced documents pertaining to BOP 

tests, actuations, and inspections at the 

facility for the duration of the 

completion activity; and 

(7) After completion of the well, you 

must retain all the records listed in 

paragraph (i)(6) of this section for a 

period of 2 years at the facility, at the 

lessee’s field office nearest the OCS 

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 be 

made to monitor the production casing below the mudline for casing pressure. 

* Characterized as a well drilled with a subsea wellhead and completed with a surface casing head, a surface tubing head, a surface tubing 

hanger, and a surface christmas tree. 

(d) Wellhead, tree, and related 

equipment shall have a pressure rating 

greater than the shut-in tubing pressure 

and shall be designed, installed, used, 

maintained, and tested so as to achieve 

and maintain pressure control. New 

wells completed as flowing or gas-lift 

wells shall be equipped with a 

minimum of one master valve and one 

surface safety valve, installed above the 

master valve, in the vertical run of the 

tree. 

(e) Subsurface safety equipment shall 

be installed, maintained, and tested in 

compliance with § 250.801 of this part. 

Casing Pressure Management 

§ 250.518 What are the requirements for 

casing pressure management? 

Once you install your wellhead, you 

must meet the casing pressure 

management requirements of API RP 90 

(as incorporated by reference in 

§ 250.198) and the requirements of 

§§ 250.519 through 250.530. If there is a 

conflict between API RP 90 and the 

casing pressure requirements of this 

subpart, you must follow the 

requirements of this subpart. 

§ 250.519 How often do I have to monitor 

for casing pressure? 

You must monitor for casing pressure 

in your well according to the following 

table: 

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: 

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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 H2S that may 

be present; 

(v) Whether the structure on which 

the well is located is manned or 

unmanned; 

(w) Additional comments; and 

(x) Request date. 

§ 250.528 What are the terms of my casing 

pressure request? 

Casing pressure requests are approved 

by the Regional Supervisor, Field 

Operations, for a term to be determined 

by the Regional Supervisor on a case-bycase basis. The Regional Supervisor may 

impose additional restrictions or 

requirements to allow continued 

operation of the well. 

§ 250.529 What if my casing pressure 

request is denied? 

(a) If your casing pressure request is 

denied, then the operating company 

must submit plans for corrective action 

to the respective District Manager 

within 30 days of receiving the denial. 

The District Manager will establish a 

specific time period in which this 

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 of 

operation. The well to which a wellworkover rig or related equipment is to 

be moved shall also be equipped with 

a back-pressure valve prior to removing 

the tree and installing and testing the 

blowout-preventer (BOP) system. The 

well from which a well-workover rig or 

related equipment is to be moved shall 

also be equipped with a back pressure 

valve prior to removing the BOP system 

and installing the tree. Coiled tubing 

units, snubbing units, or wireline units 

may be moved onto a platform without 

shutting in wells. 

§ 250.603 Emergency shutdown system. 

When well-workover operations are 

conducted on a well with the tree 

removed, an emergency shutdown 

system (ESD) manually controlled 

station shall be installed near the 

driller’s console or well-servicing unit 

operator’s work station, except when 

there is no other hydrocarbon-producing 

well or other hydrocarbon flow on the 

platform. 

§ 250.604 Hydrogen sulfide. 

When a well-workover operation is 

conducted in zones known to contain 

hydrogen sulfide (H2S) or in zones 

where the presence of H2S is unknown 

(as defined in § 250.490 of this part), the 

lessee shall take appropriate precautions 

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to protect life and property on the 

platform or rig, including but not 

limited to operations such as blowing 

the well down, dismantling wellhead 

equipment and flow lines, circulating 

the well, swabbing, and pulling tubing, 

pumps and packers. The lessee shall 

comply with the requirements in 

§ 250.490 of this part as well as the 

appropriate requirements of this 

subpart. 

§ 250.605 Subsea workovers. 

No subsea well-workover operation 

including routine operations shall be 

commenced until the lessee obtains 

written approval from the District 

Manager in accordance with § 250.613 

of this part. That approval shall be 

based upon a case-by-case 

determination that the proposed 

equipment and procedures will 

maintain adequate control of the well 

and permit continued safe production 

operations. 

§ 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 to 

moving a well-workover rig or wellservicing equipment onto a platform, 

the lessee shall determine the structural 

capability of the platform to safely 

support the equipment and proposed 

operations, taking into consideration the 

corrosion protection, age of the 

platform, and previous stresses to the 

platform. 

§ 250.610 Diesel engine air intakes. 

No later than May 31, 1989, diesel 

engine air intakes shall be equipped 

with a device to shut down the diesel 

engine in the event of runaway. Diesel 

engines which are continuously 

attended shall be equipped with either 

remote operated manual or automatic 

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 other 

requirements of this subpart. Field wellworkover rules may be amended or 

canceled for cause at any time upon the 

initiative of the District Manager or 

upon the request of a lessee. 

§ 250.613 Approval and reporting for wellworkover 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 H2S or a zone 

where the presence of H2S is unknown, 

information pursuant to § 250.490 of 

this part; and 

(4) Payment of the service fee listed in 

§ 250.125. 

(c) The following additional 

information shall be submitted with 

Form BSEE–0124 if completing to a new 

zone is proposed: 

(1) Reason for abandonment of 

present producing zone including 

supportive well test data, and 

(2) A statement of anticipated or 

known pressure data for the new zone. 

(d) Within 30 days after completing 

the well-workover operation, except 

routine operations, Form BSEE–0124, 

Application for Permit to Modify, shall 

be submitted to the District Manager, 

showing the work as performed. In the 

case of a well-workover operation 

resulting in the initial recompletion of 

a well into a new zone, a Form BSEE– 

0125, End of Operations Report, shall be 

submitted to the District Manager and 

shall include a new schematic of the 

tubing subsurface equipment if any 

subsurface equipment has been 

changed. 

§ 250.614 Well-control fluids, equipment, 

and operations. 

The following requirements apply 

during all well-workover operations 

with the tree removed: 

(a) Well-control fluids, equipment, 

and operations shall be designed, 

utilized, maintained, and/or tested as 

necessary to control the well in 

foreseeable conditions and 

circumstances, including subfreezing 

conditions. The well shall be 

continuously monitored during wellworkover operations and shall not be 

left unattended at anytime unless the 

well is shut in and secured. 

(b) When coming out of the hole with 

drill pipe or a workover string, the 

annulus shall be filled with well-control 

fluid before the change in such fluid 

level decreases the hydrostatic pressure 

75 pounds per square inch (psi) or every 

five stands of drill pipe or workover 

string, whichever gives a lower decrease 

in hydrostatic pressure. The number of 

stands of drill pipe or workover string 

and drill collars that may be pulled 

prior to filling the hole and the 

equivalent well-control fluid volume 

shall be calculated and posted near the 

operator’s station. A mechanical, 

volumetric, or electronic device for 

measuring the amount of well-control 

fluid required to fill the hold shall be 

utilized. 

(c) The following well-control-fluid 

equipment shall be installed, 

maintained, and utilized: 

(1) A fill-up line above the uppermost 

BOP; 

(2) A well-control, fluid-volume 

measuring device for determining fluid 

volumes when filling the hole on trips; 

and 

(3) A recording mud-pit-level 

indicator to determine mud-pit-volume 

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gains and losses. This indicator shall 

include both a visual and an audible 

warning device. 

§ 250.615 Blowout prevention equipment. 

(a) The BOP system, system 

components and related well-control 

equipment shall be designed, used, 

maintained, and tested in a manner 

necessary to assure well control in 

foreseeable conditions and 

circumstances, including subfreezing 

conditions. The working pressure rating 

of the BOP system and system 

components shall exceed the expected 

surface pressure to which they may be 

subjected. If the expected surface 

pressure exceeds the rated working 

pressure of the annular preventer, the 

lessee shall submit with Form BSEE– 

0124, requesting approval of the 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 inside 

of conventional tubing using smalldiameter jointed pipe (usually 3⁄4 inch to 

11⁄4 inch) as a work string, i.e., smalltubing operations, shall include the 

following: 

(1) Two sets of pipe rams, and 

(2) One set of blind rams. 

(e) The subsea BOP system for wellworkover operations must meet the 

requirements in § 250.442 of this part. 

(f) For coiled tubing operations with 

the production tree in place, you must 

meet the following minimum 

requirements for the BOP system: 

(1) BOP system components must be 

in the following order from the top 

down: 

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. 

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(2) You may use a set of 

hydraulically-operated combination 

rams for the blind rams and shear rams. 

(3) You may use a set of 

hydraulically-operated combination 

rams for the hydraulic two-way slip 

rams and the hydraulically-operated 

pipe rams. 

(4) You must attach a dual check 

valve assembly to the coiled tubing 

connector at the downhole end of the 

coiled tubing string for all coiled tubing 

well-workover operations. If you plan to 

conduct operations without downhole 

check valves, you must describe 

alternate procedures and equipment in 

Form BSEE–0124, Application for 

Permit to Modify and have it approved 

by the District Manager. 

(5) You must have a kill line and a 

separate choke line. You must equip 

each line with two full-opening valves 

and at least one of the valves must be 

remotely controlled. You may use a 

manual valve instead of the remotely 

controlled valve on the kill line if you 

install a check valve between the two 

full-opening manual valves and the 

pump or manifold. The valves must 

have a working pressure rating equal to 

or greater than the working pressure 

rating of the connection to which they 

are attached, and you must install them 

between the well control stack and the 

choke or kill line. For operations with 

expected surface pressures greater than 

3,500 psi, the kill line must be 

connected to a pump or manifold. You 

must not use the kill line inlet on the 

BOP stack for taking fluid returns from 

the wellbore. 

(6) You must have a hydraulicactuating system that provides sufficient 

accumulator capacity to close-openclose each component in the BOP stack. 

This cycle must be completed with at 

least 200 psi above the pre-charge 

pressure, without assistance from a 

charging system. 

(7) All connections used in the 

surface BOP system from the tree to the 

uppermost required ram must be 

flanged, including the connections 

between the well control stack and the 

first full-opening valve on the choke 

line and the kill line. 

(g) The minimum BOP-system 

components for well-workover 

operations with the tree in place and 

performed by moving tubing or drill 

pipe in or out of a well under pressure 

utilizing equipment specifically 

designed for that purpose, i.e., snubbing 

operations, shall include the following: 

(1) One set of pipe rams hydraulically 

operated, and 

(2) Two sets of stripper-type pipe 

rams hydraulically operated with spacer 

spool. 

(h) An inside BOP or a spring-loaded, 

back-pressure safety valve and an 

essentially full-opening, work-string 

safety valve in the open position shall 

be maintained on the rig floor at all 

times during well-workover operations 

when the tree is removed or during 

well-workover operations with the tree 

installed and using small tubing as the 

work string. A wrench to fit the workstring safety valve shall be readily 

available. Proper connections shall be 

readily available for inserting valves in 

the work string. The full-opening safety 

valve is not required for coiled tubing or 

snubbing operations. 

§ 250.616 Blowout preventer system 

testing, records, and drills. 

(a) BOP pressure tests. When you 

pressure test the BOP system you must 

conduct a low-pressure test and a highpressure test for each component. You 

must conduct the low-pressure test 

before the high-pressure test. For 

purposes of this section, BOP system 

components include ram-type BOP’s, 

related control equipment, choke and 

kill lines, and valves, manifolds, 

strippers, and safety valves. Surface 

BOP systems must be pressure tested 

with water. 

(1) Low pressure tests. All BOP system 

components must be successfully tested 

to a low pressure between 200 and 300 

psi. Any initial pressure equal to or 

greater than 300 psi must be bled back 

to a pressure between 200 and 300 psi 

before starting the test. If the initial 

pressure exceeds 500 psi, you must 

bleed back to zero before starting the 

test. 

(2) High pressure tests. All BOP 

system components must be 

successfully tested to the rated working 

pressure of the BOP equipment, or as 

otherwise approved by the District 

Manager. The annular-type BOP must be 

successfully tested at 70 percent of its 

rated working pressure or as otherwise 

approved by the District Manager. 

(3) Other testing requirements. 

Variable bore pipe rams must be 

pressure tested against the largest and 

smallest sizes of tubulars in use (jointed 

pipe, seamless pipe) in the well. 

(b) Times. The BOP systems shall be 

tested at the following times: 

(1) When installed; 

(2) At least every 7 days, alternating 

between control stations and at 

staggered intervals to allow each crew to 

operate the equipment. If either control 

system is not functional, further 

operations shall be suspended until the 

nonfunctional, system is operable. The 

test every 7 days is not required for 

blind or blind-shear rams. The blind or 

blind-shear rams shall be tested at least 

once every 30 days during operation. A 

longer period between blowout 

preventer tests is allowed when there is 

a stuck pipe or pressure-control 

operation and remedial efforts are being 

performed. The tests shall be conducted 

as soon as possible and before normal 

operations resume. The reason for 

postponing testing shall be entered into 

the operations log. 

(3) Following repairs that require 

disconnecting a pressure seal in the 

assembly, the affected seal will be 

pressure tested. 

(c) Drills. All personnel engaged in 

well-workover operations shall 

participate in a weekly BOP drill to 

familiarize crew members with 

appropriate safety measures. 

(d) Stump tests. You may conduct a 

stump test for the BOP system on 

location. A plan describing the stump 

test procedures must be included in 

your Form BSEE–0124, Application for 

Permit to Modify, and must be approved 

by the District Manager. 

(e) Coiled tubing tests. You must test 

the coiled tubing connector to a low 

pressure of 200 to 300 psi, followed by 

a high pressure test to the rated working 

pressure of the connector or the 

expected surface pressure, whichever is 

less. You must successfully pressure test 

the dual check valves to the rated 

working pressure of the connector, the 

rated working pressure of the dual 

check valve, expected surface pressure, 

or the collapse pressure of the coiled 

tubing, whichever is less. 

(f) Recordings. You must record test 

pressures during BOP and coiled tubing 

tests on a pressure chart, or with a 

digital recorder, unless otherwise 

approved by the District Manager. The 

test interval for each BOP system 

component must be 5 minutes, except 

for coiled tubing operations, which 

must include a 10 minute high-pressure 

test for the coiled tubing string. Your 

representative at the facility must certify 

that the charts are correct. 

(g) Operations log. The time, date, and 

results of all pressure tests, actuations, 

inspections, and crew drills of the BOP 

system, system components, and marine 

risers shall be recorded in the 

operations log. The BOP tests shall be 

documented in accordance with the 

following: 

(1) The documentation shall indicate 

the sequential order of BOP and 

auxiliary equipment testing and the 

pressure and duration of each test. As 

an alternate, the documentation in the 

operations log may reference a BOP test 

plan that contains the required 

information and is retained on file at the 

facility. 

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(2) The control station used during 

the test shall be identified in the 

operations log. For a subsea system, the 

pod used during the test shall be 

identified in the operations log. 

(3) Any problems or irregularities 

observed during BOP and auxiliary 

equipment testing and any actions taken 

to remedy such problems or 

irregularities shall be noted in the 

operations log. 

(4) Documentation required to be 

entered in the operation log may instead 

be referenced in the operations log. All 

records including pressure charts, 

operations log, and referenced 

documents pertaining to BOP tests, 

actuations, and inspections, shall be 

available for BSEE review at the facility 

for the duration of well-workover 

activity. Following completion of the 

well-workover activity, all such records 

shall be retained for a period of 2 years 

at the facility, at the lessee’s filed office 

nearest the OCS facility, or at another 

location conveniently available to the 

District Manager. 

(h) Subsea BOPs. Stump test a subsea 

BOP system before installation. You 

must: 

(1) Test all ROV intervention 

functions on your subsea BOP stack 

during the stump test. You must also 

test at least one set of rams during the 

initial test on the seafloor. You must 

submit test procedures with your APM 

for District Manager approval. You 

must: 

(i) Ensure that the ROV hot stabs are 

function tested and are capable of 

actuating, at a minimum, one set of pipe 

rams and one set of blind-shear rams 

and unlatching the LMRP; 

(ii) Document all your test results and 

make them available to BSEE upon 

request; and 

(2) Function test autoshear and 

deadman systems on your subsea BOP 

stack during the stump test. You must 

also test the deadman system during the 

initial test on the seafloor. You must: 

(i) Submit test procedures with your 

APM for District Manager approval. 

(ii) Document the results of each test 

and make them available to BSEE upon 

request. 

(3) Use water to stump test a subsea 

BOP system. You may use drilling or 

completion fluids to conduct 

subsequent tests of a subsea BOP 

system. 

§ 250.617 What are my BOP inspection 

and maintenance requirements? 

(a) BOP inspections. (1) You must 

inspect your BOP system to ensure that 

the equipment functions properly. The 

BOP inspections must meet or exceed 

the provisions of Sections 17.10 and 

18.10, Inspections, described in API RP 

53, Recommended Practices for Blowout 

Prevention Equipment Systems for 

Drilling Wells (as incorporated by 

reference in § 250.198). You must 

document the procedures used, record 

the results, and make them available to 

BSEE upon request. You must maintain 

your records on the rig for 2 years or 

from the date of your last major 

inspection, whichever is longer. 

(2) You must visually inspect your 

BOP system and marine riser at least 

once each day if weather and sea 

conditions permit. You may use 

television cameras to inspect this 

equipment. The District Manager may 

approve alternate methods and 

frequencies to inspect a marine riser. 

(b) BOP maintenance. You must 

maintain your BOP system to ensure 

that the equipment functions properly. 

The BOP maintenance must meet or 

exceed the provisions of Sections 17.11 

and 18.11, Maintenance; and Sections 

17.12 and 18.12, Quality Management, 

described in API RP 53, Recommended 

Practices for Blowout Prevention 

Equipment Systems for Drilling Wells 

(as incorporated by reference in 

§ 250.198). You must document the 

procedures used, record the results, and 

make them available to BSEE upon 

request. You must maintain your 

records on the rig for 2 years or from the 

date of your last major inspection, 

whichever is longer. 

§ 250.618 Tubing and wellhead equipment. 

The lessee shall comply with the 

following requirements during wellworkover operations with the tree 

removed: 

(a) No tubing string shall be placed in 

service or continue to be used unless 

such tubing string has the necessary 

strength and pressure integrity and is 

otherwise suitable for its intended use. 

(b) In the event of prolonged 

operations such as milling, fishing, 

jarring, or washing over that could 

damage the casing, the casing shall be 

pressure tested, calipered, or otherwise 

evaluated every 30 days and the results 

submitted to the District Manager. 

(c) When reinstalling the tree, you 

must: 

(1) Equip wells to monitor for casing 

pressure according to the following 

chart: 

If you have . . . you must equip . . . so you can monitor . . . 

(i) fixed platform wells, 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 be 

made to monitor the production casing below the mudline for casing pressure. 

* Characterized as a well drilled with a subsea wellhead and completed with a surface casing head, a surface tubing head, a surface tubing 

hanger, and a surface christmas tree. 

(2) Follow the casing pressure 

management requirements in subpart E 

of this part. 

(d) Wellhead, tree, and related 

equipment shall have a pressure rating 

greater than the shut-in tubing pressure 

and shall be designed, installed, used, 

maintained, and tested so as to achieve 

and maintain pressure control. The tree 

shall be equipped with a minimum of 

one master valve and one surface safety 

valve in the vertical run of the tree 

when it is reinstalled. 

(e) Subsurface safety equipment shall 

be installed, maintained, and tested in 

compliance with § 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. 

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(c) When the lubricator is initially 

installed on the well, it shall be 

successfully pressure tested to the 

expected shut-in surface pressure. 

Subpart G [Reserved] 

Subpart H—Oil and Gas Production 

Safety Systems 

§ 250.800 General requirements. 

(a) Production safety equipment shall 

be designed, installed, used, 

maintained, and tested in a manner to 

assure the safety and protection of the 

human, marine, and coastal 

environments. Production safety 

systems operated in subfreezing 

climates shall utilize equipment and 

procedures selected with consideration 

of floating ice, icing, and other extreme 

environmental conditions that may 

occur in the area. Production shall not 

commence until the production safety 

system has been approved and a 

preproduction inspection has been 

requested by the lessee. 

(b) For all new floating production 

systems (FPSs) (e.g., column-stabilizedunits (CSUs); floating production, 

storage and offloading facilities (FPSOs); 

tension-leg platforms (TLPs); spars, 

etc.), you must do all of the following: 

(1) Comply with API RP 14J (as 

incorporated by reference in 30 CFR 

250.198); 

(2) Meet the drilling and production 

riser standards of API RP 2RD (as 

incorporated by reference in 30 CFR 

250.198); 

(3) Design all stationkeeping systems 

for floating facilities to meet the 

standards of API RP 2SK (as 

incorporated by reference in 30 CFR 

250.198), as well as relevant U.S. Coast 

Guard regulations; and 

(4) Design stationkeeping systems for 

floating facilities to meet structural 

requirements in subpart I, §§ 250.900 

through 250.921 of this part. 

§ 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 not 

previously equipped with a surfacecontrolled SSSV and wells in which a 

surface-controlled SSSV has been 

replaced with a subsurface-controlled 

SSSV in accordance with paragraph 

(d)(2) of this section shall be equipped 

with a surface-controlled SSSV when 

the tubing is first removed and 

reinstalled. 

(d) Subsurface-controlled SSSVs. 

Wells may be equipped with subsurfacecontrolled SSSVs in lieu of a surfacecontrolled SSSV provided the lessee 

demonstrates to the District Manager’s 

satisfaction that one of the following 

criteria are met: 

(1) Wells not previously equipped 

with surface-controlled SSSVs shall be 

so equipped when the tubing is first 

removed and reinstalled, 

(2) The subsurface-controlled SSSV is 

installed in wells completed from a 

single-well or multiwell satellite caisson 

or seafloor completions, or 

(3) The subsurface-controlled SSSV is 

installed in wells with a surfacecontrolled SSSV that has become 

inoperable and cannot be repaired 

without removal and reinstallation of 

the tubing. 

(e) Design, installation, and operation 

of SSSVs. The SSSVs shall be designed, 

installed, operated, and maintained to 

ensure reliable operation. 

(1) The device shall be installed at a 

depth of 100 feet or more below the 

seafloor within 2 days after production 

is established. When warranted by 

conditions such as permafrost, unstable 

bottom conditions, hydrate formation, 

or paraffins, an alternate setting depth of 

the subsurface safety device may be 

approved by the District Manager. 

(2) Until a subsurface safety device is 

installed, the well shall be attended in 

the immediate vicinity so that 

emergency actions may be taken while 

the well is open to flow. During testing 

and inspection procedures, the well 

shall not be left unattended while open 

to production unless a properly 

operating subsurface-safety device has 

been installed in the well. 

(3) The well shall not be open to flow 

while the subsurface safety device is 

removed, except when flowing of the 

well is necessary for a particular 

operation such as cutting paraffin, 

bailing sand, or similar operations. 

(4) All SSSVs must be inspected, 

installed, maintained, and tested in 

accordance with American Petroleum 

Institute Recommended Practice 14B, 

Recommended Practice for Design, 

Installation, Repair, and Operation of 

Subsurface Safety Valve Systems (as 

specified in § 250.198). 

(f) Subsurface safety devices in shutin wells. (1) New completions 

(perforated but not placed on 

production) and completions shut in for 

a period of 6 months shall be equipped 

with either— 

(i) A pump-through-type tubing plug; 

(ii) A surface-controlled SSSV, 

provided the surface control has been 

rendered inoperative; or 

(iii) An injection valve capable of 

preventing backflow. 

(2) The setting depth of the subsurface 

safety device shall be approved by the 

District Manager on a case-by-case basis, 

when warranted by conditions such as 

permafrost, unstable bottom conditions, 

hydrate formations, and paraffins. 

(g) Subsurface safety devices in 

injection wells. A surface-controlled 

SSSV or an injection valve capable of 

preventing backflow shall be installed 

in all injection wells. This requirement 

is not applicable if the District Manager 

concurs that the well is incapable of 

flowing. The lessee shall verify the noflow condition of the well annually. 

(h) Temporary removal for routine 

operations. (1) Each wireline- or 

pumpdown-retrievable subsurface safety 

device may be removed, without further 

authorization or notice, for a routine 

operation which does not require the 

approval of a Form BSEE–0124, 

Application for Permit to Modify, in 

§ 250.601 of this part for a period not to 

exceed 15 days. 

(2) The well shall be identified by a 

sign on the wellhead stating that the 

subsurface safety device has been 

removed. The removal of the subsurface 

safety device shall be noted in the 

records as required in § 250.804(b) of 

this part. If the master valve is open, a 

trained person shall be in the immediate 

vicinity of the well to attend the well so 

that emergency actions may be taken, if 

necessary. 

(3) A platform well shall be 

monitored, but a person need not 

remain in the well-bay area 

continuously if the master valve is 

closed. If the well is on a satellite 

structure, it must be attended or a 

pump-through plug installed in the 

tubing at least 100 feet below the mud 

line and the master valve closed, unless 

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otherwise approved by the District 

Manager. 

(4) The well shall not be allowed to 

flow while the subsurface safety device 

is removed, except when flowing the 

well is necessary for that particular 

operation. The provisions of this 

paragraph are not applicable to the 

testing and inspection procedures in 

§ 250.804 of this part. 

(i) Additional safety equipment. All 

tubing installations in which a wirelineor pumpdown-retrievable subsurface 

safety device is installed after the 

effective date of this subpart shall be 

equipped with a landing nipple with 

flow couplings or other protective 

equipment above and below to provide 

for the setting of the SSSV. The control 

system for all surface-controlled SSSVs 

shall be an integral part of the platform 

Emergency Shutdown System (ESD). In 

addition to the activation of the ESD by 

manual action on the platform, the 

system may be activated by a signal 

from a remote location. Surfacecontrolled SSSVs shall close in response 

to shut-in signals from the ESD and in 

response to the fire loop or other fire 

detection devices. 

(j) Emergency action. In the event of 

an emergency, such as an impending 

storm, any well not equipped with a 

subsurface safety device and which is 

capable of natural flow shall have the 

device properly installed as soon as 

possible with due consideration being 

given to personnel safety. 

§ 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, metering 

devices, and other hydrocarbonhandling vessels. 

(2) A schematic piping flow diagram 

(API RP 14C, Figure E, as incorporated 

by reference in § 250.198) and the 

related Safety analysis Function 

Evaluation chart (API RP 14C, 

subsection 4.3c, as incorporated by 

reference in § 250.198). 

(3) A schematic piping diagram 

showing the size and maximum 

allowable working pressures as 

determined in accordance with API RP 

14E, Design and Installation of Offshore 

Production Platform Piping Systems (as 

incorporated by reference in § 250.198). 

(4) Electrical system information 

including the following: 

(i) A plan for each platform deck 

outlining all hazardous areas classified 

according to API RP 500, Recommended 

Practice for Classification of Locations 

for Electrical Installations at Petroleum 

Facilities Classified as Class I, Division 

1 and Division 2, or API RP 505, 

Recommended Practice for 

Classification of Locations for Electrical 

Installations at Petroleum Facilities 

Classified as Class I, Zone 0, Zone 1, 

and Zone 2 (as incorporated by 

reference in § 250.198), and outlining 

areas in which potential ignition 

sources, other than electrical, are to be 

installed. The area outlined will include 

the following information: 

(A) All major production equipment, 

wells, and other significant hydrocarbon 

sources and a description of the type of 

decking, ceiling, walls (e.g., grating or 

solid) and firewalls; and 

(B) Location of generators, control 

rooms, panel boards, major cabling/ 

conduit routes, and identification of the 

primary wiring method (e.g., type cable, 

conduit, or wire). 

(ii) Elementary electrical schematic of 

any platform safety shut-down system 

with a functional legend. 

(5) Certification that the design for the 

mechanical and electrical systems to be 

installed were approved by registered 

professional engineers. After these 

systems are installed, the lessee shall 

submit a statement to the District 

Manager certifying that new 

installations conform to the approved 

designs of this subpart. 

(6) The design and schematics of the 

installation and maintenance of all fireand gas-detection systems shall include 

the following: 

(i) Type, location, and number of 

detection sensors; 

(ii) Type and kind of alarms, 

including emergency equipment to be 

activated; 

(iii) Method used for detection; 

(iv) Method and frequency of 

calibration; and 

(v) A functional block diagram of the 

detection system, including the electric 

power supply. 

(7) The service fee listed in § 250.125. 

The fee you must pay will be 

determined by the number of 

components involved in the review and 

approval process. 

§ 250.803 Additional production system 

requirements. 

(a) For all production platforms, you 

must comply with the following 

production safety system requirements, 

in addition to the requirements of 

§ 250.802 of this subpart and the 

requirements of API RP 14C (as 

incorporated by reference in § 250.198). 

(b) Design, installation, and operation 

of additional production systems—(1) 

Pressure and fired vessels. Pressure and 

fired vessels must be designed, 

fabricated, and code stamped in 

accordance with the applicable 

provisions of Sections I, IV, and VIII of 

the American Society of Mechanical 

Engineers (ASME) Boiler and Pressure 

Vessel Code. Pressure and fired vessels 

must have maintenance inspection, 

rating, repair, and alteration performed 

in accordance with the applicable 

provisions of API Pressure Vessel 

Inspections Code: In-Service Inspection, 

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Rating, Repair, and Alteration, API 510 

(except Sections 5.8 and 9.5) (as 

incorporated by reference in § 250.198). 

(i) Pressure relief valves shall be 

designed, installed, and maintained in 

accordance with applicable provisions 

of sections I, IV, and VIII of the ASME 

Boiler and Pressure Vessel Code. The 

relief valves shall conform to the valvesizing and pressure-relieving 

requirements specified in these 

documents; however, the relief valves, 

except completely redundant relief 

valves, shall be set no higher than the 

maximum-allowable working pressure 

of the vessel. All relief valves and vents 

shall be piped in such a way as to 

prevent fluid from striking personnel or 

ignition sources. 

(ii) Steam generators operating at less 

than 15 pounds per square inch gauge 

(psig) shall be equipped with a level 

safety low (LSL) sensor which will shut 

off the fuel supply when the water level 

drops below the minimum safe level. 

Steam generators operating at greater 

than 15 psig require, in addition to an 

LSL, a water-feeding device which will 

automatically control the water level. 

(iii) The lessee shall use pressure 

recorders to establish the new operating 

pressure ranges of pressure vessels at 

any time when there is a change in 

operating pressures that requires new 

settings for the high-pressure shut-in 

sensor and/or the low-pressure shut-in 

sensor as provided herein. The pressurerecorder charts used to determine 

current operating pressure ranges shall 

be maintained at the lessee’s field office 

nearest the OCS facility or at other 

locations conveniently available to the 

District Manager. The high-pressure 

shut-in sensor shall be set no higher 

than 15 percent or 5 psi, whichever is 

greater, above the highest operating 

pressure of the vessel. This setting shall 

also be set sufficiently below (5 percent 

or 5 psi, whichever is greater) the relief 

valve’s set pressure to assure that the 

pressure source is shut in before the 

relief valve activates. The low-pressure 

shut-in sensor shall activate no lower 

than 15 percent or 5 psi, whichever is 

greater, below the lowest pressure in the 

operating range. The activation of lowpressure sensors on pressure vessels 

which operate at less than 5 psi shall be 

approved by the District Manager on a 

case-by-case basis. 

(2) Flowlines. (i) You must equip 

flowlines from wells with high- and 

low-pressure shut-in sensors located in 

accordance with section A.1 and Figure 

A1 of API RP 14C (as incorporated by 

reference in § 250.198). The lessee shall 

use pressure recorders to establish the 

new operating pressure ranges of 

flowlines at any time when there is a 

significant change in operating 

pressures. The most recent pressurerecorder charts used to determine 

operating pressure ranges shall be 

maintained at the lessee’s field office 

nearest the OCS facility or at other 

locations conveniently available to the 

District Manager. The high-pressure 

shut-in sensor(s) shall be set no higher 

than 15 percent or 5 psi, whichever is 

greater, above the highest operating 

pressure of the line. But in all cases, it 

shall be set sufficiently below the 

maximum shut-in wellhead pressure or 

the gas-lift supply pressure to assure 

actuation of the SSV. The low-pressure 

shut-in sensor(s) shall be set no lower 

than 15 percent or 5 psi, whichever is 

greater, below the lowest operating 

pressure of the line in which it is 

installed. 

(ii) If a well flows directly to the 

pipeline before separation, the flowline 

and valves from the well located 

upstream of and including the header 

inlet valve(s) shall have a working 

pressure equal to or greater than the 

maximum shut-in pressure of the well 

unless the flowline is protected by one 

of the following: 

(A) A relief valve which vents into the 

platform flare scrubber or some other 

location approved by the District 

Manager. The platform flare scrubber 

shall be designed to handle, without 

liquid-hydrocarbon carryover to the 

flare, the maximum-anticipated flow of 

liquid hydrocarbons which may be 

relieved to the vessel. 

(B) Two SSV’s with independent 

high-pressure sensors installed with 

adequate volume upstream of any block 

valve to allow sufficient time for the 

valve(s) to close before exceeding the 

maximum allowable working pressure. 

(iii) If you are installing flowlines 

constructed of unbonded flexible pipe 

on a floating platform, you must: 

(A) Review the manufacturer’s Design 

Methodology Verification Report and 

the independent verification agent’s 

(IVA’s) certificate for the design 

methodology contained in that report to 

ensure that the manufacturer has 

complied with the requirements of API 

Spec 17J (as incorporated by reference 

in § 250.198); 

(B) Determine that the unbonded 

flexible pipe is suitable for its intended 

purpose on the lease or pipeline rightof-way; 

(C) Submit to the BSEE District 

Manager the manufacturer’s design 

specifications for the unbonded flexible 

pipe; and 

(D) Submit to the BSEE District 

Manager a statement certifying that the 

pipe is suitable for its intended use and 

that the manufacturer has complied 

with the IVA requirements of API Spec 

17J (as incorporated by reference in 

§ 250.198). 

(3) Safety sensors. All shutdown 

devices, valves, and pressure sensors 

shall function in a manual reset mode. 

Sensors with integral automatic reset 

shall be equipped with an appropriate 

device to override the automatic reset 

mode. All pressure sensors shall be 

equipped to permit testing with an 

external pressure source. 

(4) ESD. The ESD must conform to the 

requirements of Appendix C, section C1, 

of API RP 14C (as incorporated by 

reference in § 250.198), and the 

following: 

(i) The manually operated ESD 

valve(s) shall be quick-opening and 

nonrestricted to enable the rapid 

actuation of the shutdown system. Only 

ESD stations at the boat landing may 

utilize a loop of breakable synthetic 

tubing in lieu of a valve. 

(ii) Closure of the SSV shall not 

exceed 45 seconds after automatic 

detection of an abnormal condition or 

actuation of an ESD. The surfacecontrolled SSSV shall close in not more 

than 2 minutes after the shut-in signal 

has closed the SSV. Design-delayed 

closure time greater than 2 minutes 

shall be justified by the lessee based on 

the individual well’s mechanical/ 

production characteristics and be 

approved by the District Manager. 

(iii) A schematic of the ESD which 

indicates the control functions of all 

safety devices for the platforms shall be 

maintained by the lessee on the 

platform or at the lessee’s field office 

nearest the OCS facility or other 

location conveniently available to the 

District Manager. 

(5) Engines: (i) Engine exhaust. You 

must equip engine exhausts to comply 

with the insulation and personnel 

protection requirements of API RP 14C, 

section 4.2c(4) (as incorporated by 

reference in § 250.198). Exhaust piping 

from diesel engines must be equipped 

with spark arresters. 

(ii) Diesel engine air intake. All diesel 

engine air intakes must be equipped 

with a device to shutdown the diesel 

engine in the event of runaway. Diesel 

engines that are continuously attended 

must be equipped with either remote 

operated manual or automatic shutdown 

devices. Diesel engines that are not 

continuously attended must be 

equipped with automatic shutdown 

devices. 

(6) Glycol dehydration units. A 

pressure relief system or an adequate 

vent shall be installed on the glycol 

regenerator (reboiler) which will 

prevent overpressurization. The 

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discharge of the relief valve shall be 

vented in a nonhazardous manner. 

(7) Gas compressors. You must equip 

compressor installations with the 

following protective equipment as 

required in API RP 14C, Sections A4 

and A8 (as incorporated by reference in 

§ 250.198). 

(i) A Pressure Safety High (PSH), a 

Pressure Safety Low (PSL), a Pressure 

Safety Valve (PSV), and a Level Safety 

High (LSH), and an LSL to protect each 

interstage and suction scrubber. 

(ii) A Temperature Safety High (TSH) 

on each compressor discharge cylinder. 

(iii) The PSH and PSL shut-in sensors 

and LSH shut-in controls protecting 

compressor suction and interstage 

scrubbers shall be designated to actuate 

automatic shutdown valves (SDV) 

located in each compressor suction and 

fuel gas line so that the compressor unit 

and the associated vessels can be 

isolated from all input sources. All 

automatic SDV’s installed in compressor 

suction and fuel gas piping shall also be 

actuated by the shutdown of the prime 

mover. Unless otherwise approved by 

the District Manager, gas—well gas 

affected by the closure of the automatic 

SDV on a compressor suction shall be 

diverted to the pipeline or shut in at the 

wellhead. 

(iv) A blowdown valve is required on 

the discharge line of all compressor 

installations of 1,000 horsepower (746 

kilowatts) or greater. 

(8) Firefighting systems. Firefighting 

systems for both open and totally 

enclosed platforms installed for extreme 

weather conditions or other reasons 

shall conform to subsection 5.2, 

Firewater systems, of API RP 14G (as 

incorporated by reference in § 250.198), 

Fire Prevention and Control Open Type 

Offshore Production Platforms, and 

shall require approval of the District 

Manager. The following additional 

requirements shall apply for both openand closed-production platforms: 

(i) A firewater system consisting of 

rigid pipe with firehose stations or fixed 

firewater monitors shall be installed. 

The firewater system shall be installed 

to provide needed protection in all areas 

where production-handling equipment 

is located. A fixed waterspray system 

shall be installed in enclosed well-bay 

areas where hydrocarbon vapors may 

accumulate. 

(ii) Fuel or power for firewater pump 

drivers shall be available for at least 30 

minutes of run time during a platform 

shut-in. If necessary, an alternate fuel or 

power supply shall be installed to 

provide for this pump-operating time 

unless an alternate firefighting system 

has been approved by the District 

Manager. 

(iii) A firefighting system using 

chemicals may be used in lieu of a water 

system if the District Manager 

determines that the use of a chemical 

system provides equivalent fireprotection control. 

(iv) A diagram of the firefighting 

system showing the location of all 

firefighting equipment shall be posted 

in a prominent place on the facility or 

structure. 

(v) For operations in subfreezing 

climates, the lessee shall furnish 

evidence to the District Manager that the 

firefighting system is suitable for the 

conditions. 

(9) Fire- and gas-detection system. (i) 

Fire (flame, heat, or smoke) sensors 

shall be installed in all enclosed 

classified areas. Gas sensors shall be 

installed in all inadequately ventilated, 

enclosed classified areas. Adequate 

ventilation is defined as ventilation 

which is sufficient to prevent 

accumulation of significant quantities of 

vapor-air mixture in concentrations over 

25 percent of the lower explosive limit 

(LEL). One approved method of 

providing adequate ventilation is a 

change of air volume each 5 minutes or 

1 cubic foot of air-volume flow per 

minute per square foot of solid floor 

area, whichever is greater. Enclosed 

areas (e.g., buildings, living quarters, or 

doghouses) are defined as those areas 

confined on more than four of their six 

possible sides by walls, floors, or 

ceilings more restrictive to air flow than 

grating or fixed open louvers and of 

sufficient size to all entry of personnel. 

A classified area is any area classified 

Class I, Group D, Division 1 or 2, 

following the guidelines of API RP 500 

(as incorporated by reference in 

§ 250.198), or any area classified Class I, 

Zone 0, Zone 1, or Zone 2, following the 

guidelines of API RP 505 (as 

incorporated by reference in § 250.198). 

(ii) All detection systems shall be 

capable of continuous monitoring. Firedetection systems and portions of 

combustible gas-detection systems 

related to the higher gas concentration 

levels shall be of the manual-reset type. 

Combustible gas-detection systems 

related to the lower gas-concentration 

level may be of the automatic-reset type. 

(iii) A fuel-gas odorant or an 

automatic gas-detection and alarm 

system is required in enclosed, 

continuously manned areas of the 

facility which are provided with fuel 

gas. Living quarters and doghouses not 

containing a gas source and not located 

in a classified area do not require a gas 

detection system. 

(iv) The District Manager may require 

the installation and maintenance of a 

gas detector or alarm in any potentially 

hazardous area. 

(v) Fire- and gas-detection systems 

must be an approved type, designed and 

installed according to API RP 14C, API 

RP 14G, and either API RP 14F or API 

RP 14FZ (the preceding four documents 

as incorporated by reference in 

§ 250.198). 

(10) Electrical equipment. Electrical 

equipment and systems shall be 

designed, installed, and maintained in 

accordance with the requirements in 

§ 250.114 of this part. 

(11) Erosion. A program of erosion 

control shall be in effect for wells or 

fields having a history of sand 

production. The erosion-control 

program may include sand probes, Xray, ultrasonic, or other satisfactory 

monitoring methods. Records by lease, 

indicating the wells which have 

erosion-control programs in effect and 

the results of the programs, shall be 

maintained by the lessee for a period of 

2 years and shall be made available to 

BSEE upon request. 

(c) General platform operations. (1) 

Surface or subsurface safety devices 

shall not be bypassed or blocked out of 

service unless they are temporarily out 

of service for startup, maintenance, or 

testing procedures. Only the minimum 

number of safety devices shall be taken 

out of service. Personnel shall monitor 

the bypassed or blocked-out functions 

until the safety devices are placed back 

in service. Any surface or subsurface 

safety device which is temporarily out 

of service shall be flagged. 

(2) When wells are disconnected from 

producing facilities and blind flanged, 

equipped with a tubing plug, or the 

master valves have been locked closed, 

you are not required to comply with the 

provisions of API RP 14C (as 

incorporated by reference in § 250.198) 

or this regulation concerning the 

following: 

(i) Automatic fail-close SSV’s on 

wellhead assemblies, and 

(ii) The PSH and PSL shut-in sensors 

in flowlines from wells. 

(3) When pressure or atmospheric 

vessels are isolated from production 

facilities (e.g., inlet valve locked closed 

or inlet blind-flanged) and are to remain 

isolated for an extended period of time, 

safety device compliance with API RP 

14C or this subpart is not required. 

(4) All open-ended lines connected to 

producing facilities and wells shall be 

plugged or blind-flanged, except those 

lines designed to be open-ended such as 

flare or vent lines. 

(d) Welding and burning practices 

and procedures. All welding, burning, 

and hot-tapping activities shall be 

conducted according to the specific 

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requirements in §§ 250.109 through 

250.113 of this part. 

§ 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 one 

wellhead SSV and verify a surfacecontrolled SSSV closure for that well as 

indicated by control circuitry actuation. 

(12) Prior to the commencement of 

production, the lessee shall notify the 

District Manager when the lessee is 

ready to conduct a preproduction test 

and inspection of the integrated safety 

system. The lessee shall also notify the 

District Manager upon commencement 

of production in order that a complete 

inspection may be conducted. 

(b) Records. The lessee shall maintain 

records for a period of 2 years for each 

subsurface and surface safety device 

installed. These records shall be 

maintained by the lessee at the lessee’s 

field office nearest the OCS facility or 

other locations conveniently available to 

the District Manager. These records 

shall be available for review by a 

representative of BSEE. The records 

shall show the present status and 

history of each device, including dates 

and details of installation, removal, 

inspection, testing, repairing, 

adjustments, and reinstallation. 

§ 250.805 Safety device training. 

Personnel installing, inspecting, 

testing, and maintaining these safety 

devices and personnel operating the 

production platforms shall be qualified 

in accordance with 30 CFR 250, subpart 

O. 

§ 250.806 Safety and pollution prevention 

equipment quality assurance requirements. 

(a) General requirements. (1) Except 

as provided in paragraph (b)(1) of this 

section, you may install only certified 

safety and pollution prevention 

equipment (SPPE) in wells located on 

the OCS. SPPE includes the following: 

(i) Surface safety valves (SSV) and 

actuators; 

(ii) Underwater safety valves (USV) 

and actuators; and 

(iii) Subsurface safety valves (SSSV) 

and associated safety valve locks and 

landing nipples. 

(2) Certified SPPE is equipment the 

manufacturer certifies as manufactured 

under a quality assurance program BSEE 

recognizes. BSEE considers all other 

SPPE as noncertified. BSEE recognizes 

two quality assurance programs: 

(i) ANSI/ASME SPPE–1–1994 and 

SPPE–1d–1996 Addenda, Quality 

Assurance and Certification of Safety 

and Pollution Prevention Equipment 

Used in Offshore Oil and Gas 

Operations (as incorporated by reference 

in § 250.198); and 

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(ii) API Spec Q1, Specification for 

Quality Programs for the Petroleum, 

Petrochemical and Natural Gas Industry 

(as incorporated by reference in 

§ 250.198). 

(3) All SSV’s and USV’s must meet 

the technical specifications of API Spec 

6A and 6AV1. All SSSVs must meet the 

technical specifications of API 

Specification 14A (as incorporated by 

reference in § 250.198). However, SSSVs 

and related equipment planned to be 

used in high pressure high temperature 

environments must meet the additional 

requirements set forth in § 250.807. 

(4) For information on all standards 

mentioned in this section, see § 250.198. 

(b) Use of noncertified SPPE. (1) 

Before April 1, 1998, you may continue 

to use and install noncertified SPPE if 

it was in your inventory as of April 1, 

1988, and was included in a list of 

noncertified SPPE submitted to BSEE 

prior to August 29, 1988. 

(2) On or after April 1, 1998: 

(i) You may not install additional 

noncertified SPPE; and 

(ii) When noncertified SPPE that is 

already in service requires offsite repair, 

remanufacturing, or hot work such as 

welding, you must replace it with 

certified SPPE. 

(c) Recognizing other quality 

assurance programs. The BSEE will 

consider recognizing other quality 

assurance programs covering the 

manufacture of SPPE. If you want BSEE 

to evaluate other quality assurance 

programs, submit relevant information 

about the program and reasons for 

recognition by BSEE to the Chief, Office 

of Offshore Regulatory Programs; 

Bureau of Safety and Environmental 

Enforcement; MS–4020; 381 Elden 

Street, Herndon, Virginia 20170–4817. 

§ 250.807 Additional requirements for 

subsurface safety valves and related 

equipment installed in high pressure high 

temperature (HPHT) environments. 

(a) If you plan to install SSSVs and 

related equipment in an HPHT 

environment, you must submit detailed 

information with your Application for 

Permit to Drill (APD), Application for 

Permit to Modify (APM), or Deepwater 

Operations Plan (DWOP) that 

demonstrates the SSSVs and related 

equipment are capable of performing in 

the applicable HPHT environment. Your 

detailed information must include the 

following: 

(1) A discussion of the SSSVs’ and 

related equipment’s design verification 

analysis; 

(2) A discussion of the SSSVs’ and 

related equipment’s design validation 

and functional testing process and 

procedures used; and 

(3) An explanation of why the 

analysis, process, and procedures 

ensure that the SSSVs and related 

equipment are fit-for-service in the 

applicable HPHT environment. 

(b) For this section, HPHT 

environment means when one or more 

of the following well conditions exist: 

(1) The completion of the well 

requires completion equipment or well 

control equipment assigned a pressure 

rating greater than 15,000 psig or a 

temperature rating greater than 350 

degrees Fahrenheit; 

(2) The maximum anticipated surface 

pressure or shut-in tubing pressure is 

greater than 15,000 psig on the seafloor 

for a well with a subsea wellhead or at 

the surface for a well with a surface 

wellhead; or 

(3) The flowing temperature is equal 

to or greater than 350 degrees 

Fahrenheit on the seafloor for a well 

with a subsea wellhead or at the surface 

for a well with a surface wellhead. 

(c) For this section, related equipment 

includes wellheads, tubing heads, 

tubulars, packers, threaded connections, 

seals, seal assemblies, production trees, 

chokes, well control equipment, and 

any other equipment that will be 

exposed to the HPHT environment. 

§ 250.808 Hydrogen sulfide. 

Production operations in zones 

known to contain hydrogen sulfide 

(H2S) or in zones where the presence of 

H2S is unknown, as defined in § 250.490 

of this part, shall be conducted in 

accordance with that section and other 

relevant requirements of subpart H, 

Production Safety Systems. 

Subpart I—Platforms and Structures 

General Requirements for Platforms 

§ 250.900 What general requirements 

apply to all platforms? 

(a) You must design, fabricate, install, 

use, maintain, inspect, and assess all 

platforms and related structures on the 

Outer Continental Shelf (OCS) so as to 

ensure their structural integrity for the 

safe conduct of drilling, workover, and 

production operations. In doing this, 

you must consider the specific 

environmental conditions at the 

platform location. 

(b) You must also submit an 

application under § 250.905 of this 

subpart and obtain the approval of the 

Regional Supervisor before performing 

any of the activities described in the 

following table: 

Activity requiring application and approval Conditions for conducting the activity 

(1) Install a platform. This includes placing a newly constructed platform at a location or moving an existing platform to a new site.(i) You must adhere to the requirements of this subpart, including the 

industry standards in § 250.901. 

(ii) If you are installing a floating platform, you must also adhere to 

U.S. Coast Guard (USCG) regulations for the fabrication, installation, 

and inspection of floating OCS facilities. 

(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 

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Recommended Practice, Corrosion 

Control of Steel Fixed Offshore 

Structures Associated with Petroleum 

Production. 

(b) You must follow the requirements 

contained in the documents listed under 

paragraph (a) of this section insofar as 

they do not conflict with other 

provisions of 30 CFR part 250. You may 

use applicable provisions of these 

documents, as approved by the Regional 

Supervisor, for the design, fabrication, 

and installation of platforms such as 

spars, since standards specifically 

written for such structures do not exist. 

You may also use alternative codes, 

rules, or standards, as approved by the 

Regional Supervisor, under the 

conditions enumerated in § 250.141. 

(c) For information on the standards 

mentioned in this section, and where 

they may be obtained, see § 250.198 of 

this part. 

(d) The following chart summarizes 

the applicability of the industry 

standards listed in this section for fixed 

and floating platforms: 

Industry standard Applicable to . . . 

(1) ACI Standard 318–95, Building Code Requirements for Reinforced Concrete (ACI 318–95) and Commentary (ACI 318R–95), 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 facility 

is subject to the Platform Verification Program (PVP), you must submit four copies. 

(b) Location plat ................................................. Latitude and longitude coordinates, Universal 

Mercator grid-system coordinates, state 

plane coordinates in the Lambert or Transverse Mercator Projection System, and distances in feet from the nearest block lines. 

These coordinates must be based on the 

NAD (North American Datum) 27 datum 

plane coordinate system.

Your plat must be drawn to a scale of 1 inch 

equals 2,000 feet and include the coordinates of the lease block boundary lines. 

You must submit three copies. 

(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 or 

tethering 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 soil 

reports 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; production 

components; drilling, production, and pipeline risers, and riser tensioning systems; 

turrets and turret-and-hull interfaces; foundations, foundation pilings and templates, 

and anchoring systems; and mooring or 

tethering systems.

You must submit 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 exceeding 

0.85 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 each 

phase. On the timeline, you must breakout the specific scopes of work that 

inherently stand alone (e.g., deck, 

mooring systems, tendon systems, riser 

systems, turret systems). 

(e) Include your nomination of a 

Certified Verification Agent (CVA) as a 

part of each verification plan required 

by § 250.912; 

(f) Follow the additional requirements 

in §§ 250.913 through 250.918; 

(g) Obtain approval for modifications 

to approved plans and for major 

deviations from approved installation 

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procedures from the Regional 

Supervisor; and 

(h) Comply with applicable USCG 

regulations for floating OCS facilities. 

§ 250.912 What plans must I submit under 

the Platform Verification Program? 

If your platform, associated structure, 

or major modification meets the criteria 

in § 250.910, you must submit the 

following plans to the Regional 

Supervisor for approval: 

(a) Design verification plan. You may 

submit your design verification plan to 

BSEE with or subsequent to the 

submittal of your Development and 

Production Plan (DPP) or Development 

Operations Coordination Document 

(DOCD) to BOEM. Your design 

verification must be conducted by, or be 

under the direct supervision of, a 

registered professional civil or structural 

engineer or equivalent, or a naval 

architect or marine engineer or 

equivalent, with previous experience in 

directing the design of similar facilities, 

systems, structures, or equipment. For 

floating platforms, you must ensure that 

the requirements of the USCG for 

structural integrity and stability, e.g., 

verification of center of gravity, etc., 

have been met. Your design verification 

plan must include the following: 

(1) All design documentation 

specified in § 250.905 of this subpart; 

(2) Abstracts of the computer 

programs used in the design process; 

and 

(3) A summary of the major design 

considerations and the approach to be 

used to verify the validity of these 

design considerations. 

(b) Fabrication verification plan. The 

Regional Supervisor must approve your 

fabrication verification plan before you 

may initiate any related operations. 

Your fabrication verification plan must 

include the following: 

(1) Fabrication drawings and material 

specifications for artificial island 

structures and major members of 

concrete-gravity and steel-gravity 

structures; 

(2) For jacket and floating structures, 

all the primary load-bearing members 

included in the space-frame analysis; 

and 

(3) A summary description of the 

following: 

(i) Structural tolerances; 

(ii) Welding procedures; 

(iii) Material (concrete, gravel, or silt) 

placement methods; 

(iv) Fabrication standards; 

(v) Material quality-control 

procedures; 

(vi) Methods and extent of 

nondestructive examinations for welds 

and materials; and 

(vii) Quality assurance procedures. 

(c) Installation verification plan. The 

Regional Supervisor must approve your 

installation verification plan before you 

may initiate any related operations. 

Your installation verification plan must 

include: 

(1) A summary description of the 

planned marine operations; 

(2) Contingencies considered; 

(3) Alternative courses of action; and 

(4) An identification of the areas to be 

inspected. You must specify the 

acceptance and rejection criteria to be 

used for any inspections conducted 

during installation, and for the postinstallation verification inspection. 

(d) You must combine fabrication 

verification and installation verification 

plans for manmade islands or platforms 

fabricated and installed in place. 

§ 250.913 When must I resubmit Platform 

Verification Program plans? 

(a) You must resubmit any design 

verification, fabrication verification, or 

installation verification plan to the 

Regional Supervisor for approval if: 

(1) The CVA changes; 

(2) The CVA’s or assigned personnel’s 

qualifications change; or 

(3) The level of work to be performed 

changes. 

(b) If only part of a verification plan 

is affected by one of the changes 

described in paragraph (a) of this 

section, you can resubmit only the 

affected part. You do not have to 

resubmit the summary of technical 

details unless you make changes in the 

technical details. 

§ 250.914 How do I nominate a CVA? 

(a) As part of your design verification, 

fabrication verification, or installation 

verification plan, you must nominate a 

CVA for the Regional Supervisor’s 

approval. You must specify whether the 

nomination is for the design, 

fabrication, or installation phase of 

verification, or for any combination of 

these phases. 

(b) For each CVA, you must submit a 

list of documents to be forwarded to the 

CVA, and a qualification statement that 

includes the following: 

(1) Previous experience in third-party 

verification or experience in the design, 

fabrication, installation, or major 

modification of offshore oil and gas 

platforms. This should include fixed 

platforms, floating platforms, manmade 

islands, other similar marine structures, 

and related systems and equipment; 

(2) Technical capabilities of the 

individual or the primary staff for the 

specific project; 

(3) Size and type of organization or 

corporation; 

(4) In-house availability of, or access 

to, appropriate technology. This should 

include computer programs, hardware, 

and testing materials and equipment; 

(5) Ability to perform the CVA 

functions for the specific project 

considering current commitments; 

(6) Previous experience with BSEE 

requirements and procedures; 

(7) The level of work to be performed 

by the CVA. 

§ 250.915 What are the CVA’s primary 

responsibilities? 

(a) The CVA must conduct specified 

reviews according to §§ 250.916, 

250.917, and 250.918 of this subpart. 

(b) Individuals or organizations acting 

as CVAs must not function in any 

capacity that would create a conflict of 

interest, or the appearance of a conflict 

of interest. 

(c) The CVA must consider the 

applicable provisions of the documents 

listed in § 250.901(a); the alternative 

codes, rules, and standards approved 

under § 250.901(b); and the 

requirements of this subpart. 

(d) The CVA is the primary contact 

with the Regional Supervisor and is 

directly responsible for providing 

immediate reports of all incidents that 

affect the design, fabrication and 

installation of the platform. 

§ 250.916 What are the CVA’s primary 

duties during the design phase? 

(a) The CVA must use good 

engineering judgment and practices in 

conducting an independent assessment 

of the design of the platform, major 

modification, or repair. The CVA must 

ensure that the platform, major 

modification, or repair is designed to 

withstand the environmental and 

functional load conditions appropriate 

for the intended service life at the 

proposed location. 

(b) Primary duties of the CVA during 

the design phase include the following: 

Type of facility . . . The CVA must . . . 

(1) For fixed platforms and non-ship-shaped 

floating facilities, 

Conduct an independent assessment of all proposed: 

(i) Planning criteria; 

(ii) Operational requirements; 

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Type of facility . . . The CVA must . . . 

(iii) Environmental loading data; 

(iv) Load determinations; 

(v) Stress analyses; 

(vi) Material designations; 

(vii) Soil and foundation conditions; 

(viii) Safety factors; and 

(ix) Other pertinent parameters of the proposed design. 

(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 stability, e.g., verification of center of gravity, etc., have been met. The CVA must also consider: 

(i) Drilling, production, and pipeline risers, and riser tensioning systems (at least for the initial 

fabrication of these elements); 

(ii) Turrets and turret-and-hull interfaces; 

(iii) Foundation pilings and templates, and anchoring systems; and 

(iv) Mooring or tethering systems. 

(c) The CVA must submit interim 

reports and a final report to the Regional 

Supervisor, and to you, during the 

fabrication phase in accordance with the 

approved schedule required by 

§ 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, if 

the operator is different from the rightof-way grant holder. 

(3) A producing operator must 

identify for its own records, on all 

existing pipelines located on its lease or 

right-of-way, the specific points at 

which operating responsibility transfers 

to a transporting operator. 

(i) Each producing operator must, if 

practical, durably mark all of its abovewater transfer points by April 14, 1999, 

or the date a pipeline begins service, 

whichever is later. 

(ii) If it is not practical to durably 

mark a transfer point, and the transfer 

point is located above water, then the 

operator must identify the transfer point 

on a schematic located on the facility. 

(iii) If a transfer point is located below 

water, then the operator must identify 

the transfer point on a schematic and 

provide the schematic to BSEE upon 

request. 

(iv) If adjoining producing and 

transporting operators cannot agree on a 

transfer point by April 14, 1999, the 

BSEE Regional Supervisor and the 

Department of Transportation (DOT) 

Office of Pipeline Safety (OPS) Regional 

Director may jointly determine the 

transfer point. 

(4) The transfer point serves as a 

regulatory boundary. An operator may 

write to the BSEE Regional Supervisor 

to request an exception to this 

requirement for an individual facility or 

area. The Regional Supervisor, in 

consultation with the OPS Regional 

Director and affected parties, may grant 

the request. 

(5) Pipeline segments designed, 

constructed, maintained, and operated 

under DOT regulations but transferring 

to DOI regulation as of October 16, 1998, 

may continue to operate under DOT 

design and construction requirements 

until significant modifications or repairs 

are made to those segments. After 

October 16, 1998, BSEE operational and 

maintenance requirements will apply to 

those segments. 

(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 also 

suspend pipeline operations or a rightof-way grant if the Regional Supervisor 

determines that the lessee or right-ofway holder has failed to comply with a 

provision of the Act or any other 

applicable law, a provision of these or 

other applicable regulations, or a 

condition of a permit or right-of-way 

grant. 

(3) The Secretary of the Interior 

(Secretary) may cancel a pipeline permit 

or right-of-way grant in accordance with 

43 U.S.C. 1334(a)(2). A right-of-way 

grant may be forfeited in accordance 

with 43 U.S.C. 1334(e). 

§ 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 that 

exceed the applicable pressuretemperature ratings contained in those 

standards. 

(2) Pipeline flanges and flange 

accessories shall meet the minimum 

design requirements of ANSI B16.5, API 

Spec 6A, or the equivalent (as 

incorporated by reference in 30 CFR 

250.198). Each flange assembly must be 

able to withstand the maximum 

pressure at which the pipeline is to be 

operated and to maintain its physical 

and chemical properties at any 

temperature to which it is anticipated 

that it might be subjected in service. 

(3) Pipeline fittings shall have 

pressure-temperature ratings based on 

stresses for pipe of the same or 

equivalent material. The actual bursting 

strength of the fitting shall at least be 

equal to the computed bursting strength 

of the pipe. 

(4) If you are installing pipelines 

constructed of unbonded flexible pipe, 

you must design them according to the 

standards and procedures of API Spec 

17J, as incorporated by reference in 30 

CFR 250.198. 

(5) You must design pipeline risers for 

tension leg platforms and other floating 

platforms according to the design 

standards of API RP 2RD, Design of 

Risers for Floating Production Systems 

(FPSs) and Tension Leg Platforms 

(TLPs) (as incorporated by reference in 

§ 250.198). 


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(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 85⁄8

inches in diameter and installed in 

water depths of less than 200 feet shall 

be buried to a depth of at least 3 feet 

unless they are located in pipeline 

congested areas or seismically active 

areas as determined by the Regional 

Supervisor. Nevertheless, the Regional 

Supervisor may require burial of any 

pipeline if the Regional Supervisor 

determines that such burial will reduce 

the likelihood of environmental 

degradation or that the pipeline may 

constitute a hazard to trawling 

operations or other uses. A trawl test or 

diver survey may be required to 

determine whether or not pipeline 

burial is necessary or to determine 

whether a pipeline has been properly 

buried. 

(2) Pipeline valves, taps, tie-ins, 

capped lines, and repaired sections that 

could be obstructive shall be provided 

with at least 3 feet of cover unless the 

Regional Supervisor determines that 

such items present no hazard to 

trawling or other operations. A 

protective device may be used to cover 

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 facilities 

shall be protected by high- and lowpressure sensors (PSHL) to directly or 

indirectly shut in all production 

facilities. The PSHL shall be set not to 

exceed 15 percent above and below the 

normal operating pressure range. 

However, high pilots shall not be set 

above the pipeline’s MAOP. 

(4) Crossing pipelines on production 

or manned nonproduction platforms 

which do not receive production from 

the platform shall be equipped with an 

SDV immediately upon boarding the 

platform. The SDV shall be operated by 

a PSHL on the departing pipelines and 

connected to the platform automaticand remote-emergency shut-in systems. 

(5) The Regional Supervisor may 

require that oil pipelines be equipped 

with a metering system to provide a 

continuous volumetric comparison 

between the input to the line at the 

structure(s) and the deliveries onshore. 

The system shall include an alarm 

system and shall be of adequate 

sensitivity to detect variations between 

input and discharge volumes. In lieu of 

the foregoing, a system capable of 

detecting leaks in the pipeline may be 

substituted with the approval of the 

Regional Supervisor. 

(6) Pipelines incoming to a subsea tiein shall be equipped with a block valve 

and an FSV. Bidirectional pipelines 

connected to a subsea tie-in shall be 

equipped with only a block valve. 

(7) Gas-lift or water-injection 

pipelines on unmanned platforms need 

only be equipped with an FSV installed 

immediately upstream of each casing 

annulus or the first inlet valve on the 

christmas tree. 

(8) Bidirectional pipelines shall be 

equipped with a PSHL and an SDV 

immediately upon boarding each 

platform. 

(9) Pipeline pumps must comply with 

section A7 of API RP 14C (as 

incorporated by reference in § 250.198). 

The setting levels for the PSHL devices 

are specified in paragraph (b)(3) of this 

section. 

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(c) If the required safety equipment is 

rendered ineffective or removed from 

service on pipelines which are 

continued in operation, an equivalent 

degree of safety shall be provided. The 

safety equipment shall be identified by 

the placement of a sign on the 

equipment stating that the equipment is 

rendered ineffective or removed from 

service. 

§ 250.1005 Inspection requirements for 

DOI pipelines. 

(a) Pipeline routes shall be inspected 

at time intervals and methods 

prescribed by the Regional Supervisor 

for indication of pipeline leakage. The 

results of these inspections shall be 

retained for at least 2 years and be made 

available to the Regional Supervisor 

upon request. 

(b) When pipelines are protected by 

rectifiers or anodes for which the initial 

life expectancy of the cathodic 

protection system either cannot be 

calculated or calculations indicate a life 

expectancy of less than 20 years, such 

pipelines shall be inspected annually by 

taking measurements of pipe-toelectrolyte potential. 

§ 250.1006 How must I decommission and 

take out of service a DOI pipeline? 

(a) The requirements for 

decommissioning pipelines are listed in 

§ 250.1750 through § 250.1754. 

(b) The table in this section lists the 

requirements if you take a DOI pipeline 

out of service: 

If you have the pipeline out of service for: Then you must: 

(1) 1 year or less, 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, and 

type of line pipe and risers; pressureregulating devices (including backpressure regulators); sensing devices 

with associated pressure-control lines; 

PSV’s and settings; SDV’s, FSV’s, and 

block valves; and manifolds. This 

schematic drawing shall also show 

input source(s), e.g., wells, pumps, 

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 an 

approved lease term pipeline or right-ofway grant shall be submitted in 

quadruplicate to the Regional 

Supervisor. These applications need 

only address those items in the original 

application affected by the proposed 

modification. 

§ 250.1008 Reports. 

(a) The lessee, or right-of-way holder, 

shall notify the Regional Supervisor at 

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least 48 hours prior to commencing the 

installation or relocation of a pipeline or 

conducting a pressure test on a pipeline. 

(b) The lessee or right-of-way holder 

shall submit a report to the Regional 

Supervisor within 90 days after 

completion of any pipeline 

construction. The report, submitted in 

triplicate, shall include an ‘‘as-built’’ 

location plat drawn to a scale specified 

by the Regional Supervisor showing the 

location, length in Federal waters, and 

X–Y coordinates of key points; the 

completion date; the proposed date of 

first operation; and the HPT data. 

Pipeline right-of-way ‘‘as-built’’ location 

plats shall be certified by a registered 

engineer or land surveyor and show the 

boundaries of the right-of-way as 

granted. If there is a substantial 

deviation of the pipeline route as 

granted in the right-of-way, the report 

shall include a discussion of the reasons 

for such deviation. 

(c) The lessee or right-of-way holder 

shall report to the Regional Supervisor 

any pipeline taken out of service. If the 

period of time in which the pipeline is 

out of service is greater than 60 days, 

written confirmation is also required. 

(d) The lessee or right-of-way holder 

shall report to the Regional Supervisor 

when any required pipeline safety 

equipment is taken out of service for 

more than 12 hours. The Regional 

Supervisor shall be notified when the 

equipment is returned to service. 

(e) The lessee or right-of-way holder 

must notify the Regional Supervisor 

before the repair of any pipeline or as 

soon as practicable. Your notification 

must be accompanied by payment of the 

service fee listed in § 250.125. You must 

submit a detailed report of the repair of 

a pipeline or pipeline component to the 

Regional Supervisor within 30 days 

after the completion of the repairs. In 

the report you must include the 

following: 

(1) Description of repairs; 

(2) Results of pressure test; and 

(3) Date returned to service. 

(f) The Regional Supervisor may 

require that DOI pipeline failures be 

analyzed and that samples of a failed 

section be examined in a laboratory to 

assist in determining the cause of the 

failure. A comprehensive written report 

of the information obtained shall be 

submitted by the lessee to the Regional 

Supervisor as soon as available. 

(g) If the effects of scouring, soft 

bottoms, or other environmental factors 

are observed to be detrimentally 

affecting a pipeline, a plan of corrective 

action shall be submitted to the 

Regional Supervisor for approval within 

30 days of the observation. A report of 

the remedial action taken shall be 

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 while 

conducting operations within the rightof-way, the right-of-way holder shall 

immediately halt operations within the 

area of the discovery and report the 

discovery to the Regional Director. If 

investigations determine that the 

resource is significant, the Regional 

Director will inform the right-of-way 

holder how to protect it. 

(d) The Regional Supervisor shall be 

kept informed at all times of the rightof-way holder’s address and, if a 

corporation, the address of its principal 

place of business and the name and 

address of the officer or agent 

authorized to be served with process. 

(e) The right-of-way holder shall pay 

the United States or its lessees or rightof-way holders, as the case may be, the 

full value of all damages to the property 

of the United States or its said lessees 

or right-of-way holders and shall 

indemnify the United States against any 

and all liability for damages to life, 

person, or property arising from the 

occupation and use of the area covered 

by the right-of-way grant. 

(f)(1) The holder of a right-of-way oil 

or gas pipeline shall transport or 

purchase oil or natural gas produced 

from submerged lands in the vicinity of 

the pipeline without discrimination and 

in such proportionate amounts as the 

FERC may, after a full hearing with due 

notice thereof to the interested parties, 

determine to be reasonable, taking into 

account, among other things, 

conservation and the prevention of 

waste. 

(2) Unless otherwise exempted by 

FERC pursuant to 43 U.S.C. 1334(f)(2), 

the holder shall: 

(i) Provide open and 

nondiscriminatory access to a right-ofway pipeline to both owner and 

nonowner shippers, and 

(ii) Comply with the provisions of 43 

U.S.C. 1334(f)(1)(B) under which FERC 

may order an expansion of the 

throughput capacity of a right-of-way 

pipeline which is approved after 

September 18, 1978, and which is not 

located in the Gulf of Mexico or the 

Santa Barbara Channel. 

(g) The area covered by a right-of-way 

and all improvements thereon shall be 

kept open at all reasonable times for 

inspection by the Bureau of Safety and 

Environmental Enforcement (BSEE). 

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The right-of-way holder shall make 

available all records relative to the 

design, construction, operation, 

maintenance and repair, and 

investigations on or with regard to such 

area. 

(h) Upon relinquishment, forfeiture, 

or cancellation of a right-of-way grant, 

the right-of-way holder shall remove all 

platforms, structures, domes over 

valves, pipes, taps, and valves along the 

right-of-way. All of these improvements 

shall be removed by the holder within 

1 year of the effective date of the 

relinquishment, forfeiture, or 

cancellation unless this requirement is 

waived in writing by the Regional 

Supervisor. All such improvements not 

removed within the time provided 

herein shall become the property of the 

United States but that shall not relieve 

the holder of liability for the cost of 

their removal or for restoration of the 

site. Furthermore, the holder is 

responsible for accidents or damages 

which might occur as a result of failure 

to timely remove improvements and 

equipment and restore a site. An 

application for relinquishment of a 

right-of-way grant shall be filed in 

accordance with § 250.1019 of this part. 

§ 250.1011 [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, BSEE 

may initiate cancellation of the right-ofuse grant and easement under 

§ 250.1013. 

§ 250.1013 Grounds for forfeiture of 

pipeline right-of-way grants. 

Failure to comply with the Act, 

regulations, or any conditions of the 

right-of-way grant prescribed by the 

Regional Supervisor shall be grounds for 

forfeiture of the grant in an appropriate 

judicial proceeding instituted by the 

United States in any U.S. District Court 

having jurisdiction in accordance with 

the provisions of 43 U.S.C. 1349. 

§ 250.1014 When pipeline right-of-way 

grants expire. 

Any right-of-way granted under the 

provisions of this subpart remains in 

effect as long as the associated pipeline 

is properly maintained and used for the 

purpose for which the grant was made, 

unless otherwise expressly stated in the 

grant. Temporary cessation or 

suspension of pipeline operations shall 

not cause the grant to expire. However, 

if the purpose of the grant ceases to exist 

or use of the associated pipeline is 

permanently discontinued for any 

reason, the grant shall be deemed to 

have expired. 

§ 250.1015 Applications for pipeline rightof-way grants. 

(a) You must submit an original and 

three copies of an application for a new 

or modified pipeline ROW grant to the 

Regional Supervisor. The application 

must address those items required by 

§ 250.1007(a) or (b) of this subpart, as 

applicable. It must also state the 

primary purpose for which you will use 

the ROW grant. If the ROW has been 

used before the application is made, the 

application must state the date such use 

began, by whom, and the date the 

applicant obtained control of the 

improvement. When you file your 

application, you must pay the rental 

required under § 250.1012 of this 

subpart, as well as the service fees listed 

in § 250.125 of this part for a pipeline 

ROW grant to install a new pipeline, or 

to convert an existing lease term 

pipeline into a ROW pipeline. An 

application to modify an approved ROW 

grant must be accompanied by the 

additional rental required under 

§ 250.1012 if applicable. You must file 

a separate application for each ROW. 

(b)(1) An individual applicant shall 

submit a statement of citizenship or 

nationality with the application. An 

applicant who is an alien lawfully 

admitted for permanent residence in the 

United States shall also submit evidence 

of such status with the application. 

(2) If the applicant is an association 

(including a partnership), the 

application shall also be accompanied 

by a certified copy of the articles of 

association or appropriate reference to a 

copy of such articles already filed with 

BSEE and a statement as to any 

subsequent amendments. 

(3) If the applicant is a corporation, 

the application shall also include the 

following: 

(i) A statement certified by the 

Secretary or Assistant Secretary of the 

corporation with the corporate seal 

showing the State in which it is 

incorporated and the name of the 

person(s) authorized to act on behalf of 

the corporation, or 

(ii) In lieu of such a statement, an 

appropriate reference to statements or 

records previously submitted to BSEE 

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(including material submitted in 

compliance with prior regulations). 

(c) The application shall include a list 

of every lessee and right-of-way holder 

whose lease or right-of-way is 

intersected by the proposed right-ofway. The application shall also include 

a statement that a copy of the 

application has been sent by registered 

or certified mail to each such lessee or 

right-of-way holder. 

(d) The applicant shall include in the 

application an original and three copies 

of a completed Nondiscrimination in 

Employment form (YN 3341–1 dated 

July 1982). These forms are available at 

each BSEE regional office. 

(e) Notwithstanding the provisions of 

paragraph (a) of this section, the 

requirements to pay filing fees under 

that paragraph are suspended until 

January 3, 2006. 

§ 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 its 

consent to the granting of the right-ofway. In such case, the applicant, upon 

a request filed within 30 days after 

receipt of the notification of such 

rejection, shall be allowed an 

opportunity to eliminate the conflict. 

(e)(1) If the application and other 

required information are found to be in 

compliance with applicable laws and 

regulations, the right-of-way may be 

granted. The Regional Supervisor may 

prescribe, as conditions to the right-ofway grant, stipulations necessary to 

protect human, marine, and coastal 

environments, life (including aquatic 

life), property, and mineral resources 

located on or adjacent to the right-ofway. 

(2) If the Regional Supervisor 

determines that a change in the 

application should be made, the 

Regional Supervisor shall notify the 

applicant that an amended application 

shall be filed subject to stipulated 

changes. The Regional Supervisor shall 

determine whether the applicant shall 

deliver copies of the amended 

application to other parties for 

comment. 

(3) A decision to reject an application 

shall be in writing and shall state the 

reasons for the rejection. 

§ 250.1017 Requirements for construction 

under pipeline right-of-way grants. 

(a) Failure to construct the associated 

right-of-way pipeline within 5 years of 

the date of the granting of a right-of-way 

shall cause the grant to expire. 

(b)(1) A right-of-way holder shall 

ensure that the right-of-way pipeline is 

constructed in a manner that minimizes 

deviations from the right-of-way as 

granted. 

(2) If, after constructing the right-ofway pipeline, it is determined that a 

deviation from the proposed right-ofway as granted has occurred, the rightof-way holder shall— 

(i) Notify the operators of all leases 

and holders of all right-of-way grants in 

which a deviation has occurred, and 

within 60 days of the date of the 

acceptance by the Regional Supervisor 

of the completion of pipeline 

construction report, provide the 

Regional Supervisor with evidence of 

such notification; and 

(ii) Relinquish any unused portion of 

the right-of-way. 

(3) Substantial deviation of a right-ofway pipeline as constructed from the 

proposed right-of-way as granted may be 

grounds for forfeiture of the right-ofway. 

(c) If the Regional Supervisor 

determines that a significant change in 

conditions has occurred subsequent to 

the granting of a right-of-way but prior 

to the commencement of construction of 

the associated pipeline, the Regional 

Supervisor may suspend or temporarily 

prohibit the commencement of 

construction until the right-of-way grant 

is modified to the extent necessary to 

address the changed conditions. 

§ 250.1018 Assignment of pipeline right-ofway grants. 

(a) Assignment may be made of a 

right-of-way grant, in whole or of any 

lineal segment thereof, subject to the 

approval of the Regional Supervisor. An 

application for approval of an 

assignment of a right-of-way or of a 

lineal segment thereof, shall be filed in 

triplicate with the Regional Supervisor. 

(b) Any application for approval for 

an assignment, in whole or in part, of 

any right, title, or interest in a right-ofway grant must be accompanied by the 

same showing of qualifications of the 

assignees as is required of an applicant 

for a ROW in § 250.1015 of this subpart 

and must be supported by a statement 

that the assignee agrees to comply with 

and to be bound by the terms and 

conditions of the ROW grant. The 

assignee must satisfy the bonding 

requirements in 30 CFR 550.1011. No 

transfer will be recognized unless and 

until it is first approved, in writing, by 

the Regional Supervisor. The assignee 

must pay the service fee listed in 

§ 250.125 of this part for a pipeline 

ROW assignment request. 

(c) Notwithstanding the provisions of 

paragraph (b) of this section, the 

requirement to pay a filing fee under 

that paragraph is suspended until 

January 3, 2006. 

§ 250.1019 Relinquishment of pipeline 

right-of-way grants. 

A right-of-way grant or a portion 

thereof may be surrendered by the 

holder by filing a written 

relinquishment in triplicate with the 

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Regional Supervisor. It must contain 

those items addressed in §§ 250.1751 

and 250.1752 of this part. A 

relinquishment shall take effect on the 

date it is filed subject to the satisfaction 

of all outstanding debts, fees, or fines 

and the requirements in § 250.1010(h) of 

this part. 

Subpart K—Oil and Gas Production 

Requirements 

General 

§ 250.1150 What are the general reservoir 

production requirements? 

You must produce wells and 

reservoirs at rates that provide for 

economic development while 

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 H2S.

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 that 

transporting them to market or reinjecting them is not technically feasible 

or poses a significant risk of harm to 

offshore personnel or the environment. 

(b) If you burn liquid hydrocarbons 

without the required approval, or if the 

Regional Supervisor determines that 

you were negligent or could have 

avoided burning liquid hydrocarbons, 

the hydrocarbons will be considered 

avoidably lost or wasted. You must pay 

royalties on the loss or waste, according 

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 H2S? 

(a) You may not vent gas containing 

H2S, except for minor releases during 

maintenance and repair activities that 

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weighted average atmosphere 

concentration of H2S of 20 ppm or 

higher anywhere on the platform. 

(b) You may flare gas containing H2S 

only if you meet the requirements of 

§§ 250.1160, 250.1161, 250.1163, and 

the following additional requirements: 

(1) For safety or air pollution 

prevention purposes, the Regional 

Supervisor may further restrict the 

flaring of gas containing H2S. The 

Regional Supervisor will use 

information provided in the lessee’s H2S 

Contingency Plan (§ 250.490(f)), 

Exploration Plan, DPP, DOCD submitted 

to BOEM, and associated documents to 

determine the need for restrictions; and 

(2) If the Regional Supervisor 

determines that flaring at a facility or 

group of facilities may significantly 

affect the air quality of an onshore area, 

the Regional Supervisor may require 

you to conduct an air quality modeling 

analysis, under 30 CFR 550.303, to 

determine the potential effect of facility 

emissions. The Regional Supervisor may 

require monitoring and reporting, or 

may restrict or prohibit flaring, under 30 

CFR 550.303 and 30 CFR 550.304. 

(c) The Regional Supervisor may 

require you to submit monthly reports 

of flared and vented gas containing H2S. 

Each report must contain, on a daily 

basis: 

(1) The volume and duration of each 

flaring and venting occurrence; 

(2) H2S concentration in the flared or 

vented gas; and 

(3) The calculated amount of SO2

emitted. 

Other Requirements 

§ 250.1165 What must I do for enhanced 

recovery operations? 

(a) You must promptly initiate 

enhanced oil and gas recovery 

operations for all reservoirs where these 

operations would result in an increase 

in ultimate recovery of oil or gas under 

sound engineering and economic 

principles. 

(b) Before initiating enhanced 

recovery operations, you must submit a 

proposed plan to the BSEE Regional 

Supervisor and receive approval for 

pressure maintenance, secondary or 

tertiary recovery, cycling, and similar 

recovery operations intended to increase 

the ultimate recovery of oil and gas from 

a reservoir. The proposed plan must 

include, for each project reservoir, a 

geologic and engineering overview, 

Form BOEM–0127, and supporting data 

as required in § 250.1167, 30 CFR 

550.1167, and any additional 

information required by the BSEE 

Regional Supervisor. 

(c) You must report to Office of 

Natural Resources Revenue the volumes 

of oil, gas, or other substances injected, 

produced, or produced for a second 

time under 30 CFR 1210.102. 

§ 250.1166 What additional reporting is 

required for developments in the Alaska 

OCS Region? 

(a) For any development in the Alaska 

OCS Region, you must submit an annual 

reservoir management report to the 

Regional Supervisor. The report must 

contain information detailing the 

activities performed during the previous 

year and planned for the upcoming year 

that will: 

(1) Provide for the prevention of 

waste; 

(2) Provide for the protection of 

correlative rights; and 

(3) Maximize ultimate recovery of oil 

and gas. 

(b) If your development is jointly 

regulated by BSEE and the State of 

Alaska, BSEE and the Alaska Oil and 

Gas Conservation Commission will 

jointly determine appropriate reporting 

requirements to minimize or eliminate 

duplicate reporting requirements. 

(c) [Reserved] 

§ 250.1167 What information must I submit 

with forms and for approvals? 

You must submit the supporting 

information listed in the following table 

with the form identified in column 1 

and for the approvals required under 

this subpart identified in columns 2 

through 4: 

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 ................................................................................ ........................ ✔ ✔ ........................

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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)). 

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Compositional Analysis—separating 

mixtures into identifiable components 

expressed in mole percent. 

Force majeure event—an event 

beyond your control such as war, act of 

terrorism, crime, or act of nature which 

prevents you from operating the wells 

and meters on your OCS facility. 

Gas lost—gas that is neither sold nor 

used on the lease or unit nor used 

internally by the producer. 

Gas processing plant—an installation 

that uses any process designed to 

remove elements or compounds 

(hydrocarbon and non-hydrocarbon) 

from gas, including absorption, 

adsorption, or refrigeration. Processing 

does not include treatment operations, 

including those necessary to put gas 

into marketable conditions such as 

natural pressure reduction, mechanical 

separation, heating, cooling, 

dehydration, desulphurization, and 

compression. The changing of pressures 

or temperatures in a reservoir is not 

processing. 

Gas processing plant statement—a 

monthly statement showing the volume 

and quality of the inlet or field gas 

stream and the plant products recovered 

during the period, volume of plant fuel, 

flare and shrinkage, and the allocation 

of these volumes to the sources of the 

inlet stream. 

Gas royalty meter malfunction—an 

error in any component of the gas 

measurement system which exceeds 

contractual tolerances. 

Gas volume statement—a monthly 

statement showing gas measurement 

data, including the volume (Mcf) and 

quality (Btu) of natural gas which 

flowed through a meter. 

Inventory tank—a tank in which 

liquid hydrocarbons are stored prior to 

royalty measurement. The measured 

volumes are used in the allocation 

process. 

Liquid hydrocarbons (free liquids)— 

hydrocarbons which exist in liquid form 

at standard conditions after passing 

through separating facilities. 

Malfunction factor—a liquid 

hydrocarbon royalty meter factor that 

differs from the previous meter factor by 

an amount greater than 0.0025. 

Natural gas—a highly compressible, 

highly expandable mixture of 

hydrocarbons which occurs naturally in 

a gaseous form and passes a meter in 

vapor phase. 

Operating meter—a royalty or 

allocation meter that is used for gas or 

liquid hydrocarbon measurement for 

any period during a calibration cycle. 

Pipeline (retrograde) condensate— 

liquid hydrocarbons which drop out of 

the separated gas stream at any point in 

a pipeline during transmission to shore. 

Pressure base—the pressure at which 

gas volumes and quality are reported. 

The standard pressure base is 14.73 

psia. 

Prove—to determine (as in meter 

proving) the relationship between the 

volume passing through a meter at one 

set of conditions and the indicated 

volume at those same conditions. 

Royalty meter—a meter approved for 

the purpose of determining the volume 

of gas, oil, or other components 

removed, saved, or sold from a Federal 

lease. 

Royalty tank—an approved tank in 

which liquid hydrocarbons are 

measured and upon which royalty 

volumes are based. 

Run ticket—the invoice for liquid 

hydrocarbons measured at a royalty 

point. 

Sales meter—a meter at which 

custody transfer takes place (not 

necessarily a royalty meter). 

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 following 

approved 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. 

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Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations 64567 

(2) Ensure that the royalty meter 

facilities accomplish the following: 

(i) Prevent flow reversal through the 

meter; 

(ii) Protect meters subjected to 

pressure pulsations or surges; 

(iii) Prevent the meter from being 

subjected to shock pressures greater 

than the maximum working pressure; 

and 

(iv) Prevent meter bypassing. 

(3) Maintain royalty meter facilities to 

ensure the following: 

(i) Meters operate within the gravity 

range specified by the manufacturer; 

(ii) Meters operate within the 

manufacturer’s specifications for 

maximum and minimum flow rate for 

linear accuracy; and 

(iii) Meters are reproven when 

changes in metering conditions affect 

the meters’ performance such as 

changes in pressure, temperature, 

density (water content), viscosity, 

pressure, and flow rate. 

(4) Ensure that sampling devices 

conform to the following: 

(i) The sampling point is in the 

flowstream immediately upstream or 

downstream of the meter or divert valve 

in accordance with the API MPMS (as 

incorporated by reference in § 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 use 

when proving meters with a mechanicaldisplacement prover, tank prover, or 

master meter? Calculate the following 

correction factors using the API MPMS: 

(1) The change in prover volume due 

to the effect of temperature on steel 

(Cts); 

(2) The change in prover volume due 

to the effect of pressure on steel (Cps); 

(3) The change in liquid volume due 

to the effect of temperature on a liquid 

(Ctl); and 

(4) The change in liquid volume due 

to the effect of pressure on a liquid 

(Cpl). 

(h) What are the requirements for 

establishing and applying operating 

meter factors for liquid hydrocarbons? 

(1) If you use a mechanicaldisplacement prover, you must record 

proof runs until five out of six 

consecutive runs produce a difference 

between individual runs of no greater 

than .05 percent. You must use the 

average of the five accepted runs to 

compute the meter factor. 

(2) If you use a master meter, you 

must record proof runs until three 

consecutive runs produce a total meter 

factor difference of no greater than 

0.0005. The flow rate through the meters 

during the proving must be within 10 

percent of the rate at which the line 

meter will operate. The final meter 

factor is determined by averaging the 

meter factors of the three runs; 

(3) If you use a tank prover, you must 

record proof runs until two consecutive 

runs produce a meter factor difference 

of no greater than .0005. The final meter 

factor is determined by averaging the 

meter factors of the two runs; and 

(4) You must apply operating meter 

factors forward starting with the date of 

the proving. 

(i) Under what circumstances does a 

liquid hydrocarbon royalty meter need 

to be taken out of service, and what 

must I do? (1) If the difference between 

the meter factor and the previous factor 

exceeds 0.0025 it is a malfunction 

factor, and you must: 

(i) Remove the meter from service and 

inspect it for damage or wear; 

(ii) Adjust or repair the meter, and 

reprove it; 

(iii) Apply the average of the 

malfunction factor and the previous 

factor to the production measured 

through the meter between the date of 

the previous factor and the date of the 

malfunction factor; and 

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(iv) Indicate that a meter malfunction 

occurred and show all appropriate 

remarks regarding subsequent repairs or 

adjustments on the proving report. 

(2) If a meter fails to register 

production, you must: 

(i) Remove the meter from service, 

repair and reprove it; 

(ii) Apply the previous meter factor to 

the production run between the date of 

that factor and the date of the failure; 

and 

(iii) Estimate and report unregistered 

production on the run ticket. 

(3) If the results of a royalty meter 

proving exceed the run tolerance criteria 

and all measures excluding the 

adjustment or repair of the meter cannot 

bring results within tolerance, you must: 

(i) Establish a factor using proving 

results made before any adjustment or 

repair of the meter; and 

(ii) Treat the established factor like a 

malfunction factor (see paragraph (i)(1) 

of this section). 

(j) How must I correct gross liquid 

hydrocarbon volumes to standard 

conditions? To correct gross liquid 

hydrocarbon volumes to standard 

conditions, you must: 

(1) Include Cpl factors in the meter 

factor calculation or list and apply them 

on the appropriate run ticket. 

(2) List Ctl factors on the appropriate 

run ticket when the meter is not 

automatically temperature 

compensated. 

(k) What are the requirements for 

liquid hydrocarbon allocation meters? 

For liquid hydrocarbon allocation 

meters you must: 

(1) Take samples continuously 

proportional to flow or daily (use the 

procedure in the applicable chapter of 

the API MPMS as incorporated by 

reference in § 250.198; 

(2) For turbine meters, take the 

sample proportional to the flow only; 

(3) Prove operating allocation meters 

monthly if they measure 50 or more 

barrels per day per meter the previous 

month. When a force majeure event 

precludes the required monthly meter 

proving, meters must be proved within 

15 days after being returned to service. 

The meters must be proved monthly 

thereafter; or 

(4) Prove operating allocation meters 

quarterly if they measure less than 50 

barrels per day per meter the previous 

month. When a force majeure event 

precludes the required quarterly meter 

proving, meters must be proved within 

15 days after being returned to service. 

The meters must be proved quarterly 

thereafter; 

(5) Keep a copy of the proving reports 

at the field location for 2 years; 

(6) Adjust and reprove the meter if the 

meter factor differs from the previous 

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 

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Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations 64569 

royalty determination? If natural gas 

from a Federal lease on the OCS is 

transferred to a gas plant before royalty 

determination: 

(1) You must provide the following to 

the Regional Supervisor upon request: 

(i) A copy of the monthly gas 

processing plant allocation statement; 

and 

(ii) Gross heating values of the inlet 

and residue streams when not reported 

on the gas plant statement. 

(2) You must permit BSEE to inspect 

the measurement and sampling 

equipment of natural gas processing 

plants that process Federal production. 

(f) What are the requirements for 

measuring gas lost or used on a lease? 

(1) You must either measure or estimate 

the volume of gas lost or used on a 

lease. 

(2) If you measure the volume, 

document the measurement equipment 

used and include the volume measured. 

(3) If you estimate the volume, 

document the estimating method, the 

data used, and the volumes estimated. 

(4) You must keep the documentation, 

including the volume data, easily 

obtainable for inspection at the field 

location for at least 2 years, and must 

retain the documentation at a location of 

your choosing for at least 7 years after 

the documentation is generated, subject 

to all other document retention and 

production requirements in 30 U.S.C. 

1713 and 30 CFR part 1212. 

(5) Upon the request of the Regional 

Supervisor, you must provide copies of 

the records. 

§ 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 

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substances, and the unit operator no 

longer conducts drilling or wellworkover operations (§ 250.180) under 

the unit agreement, unless the Regional 

Supervisor orders or approves a 

suspension of production under 

§ 250.170. 

(e) Unit operating agreement. The unit 

operator and the owners of working 

interests in the unitized leases must 

enter into a unit operating agreement. 

The unit operating agreement must 

describe how all the unit participants 

will apportion all costs and liabilities 

incurred maintaining or conducting 

operations. When a unit involves one or 

more net-profit-share leases, the unit 

operating agreement must describe how 

to attribute costs and credits to the netprofit-share lease(s), and this part of the 

agreement must be approved by the 

Regional Supervisor. Otherwise, you 

must provide a copy of the unit 

operating agreement to the Regional 

Supervisor, but the Regional Supervisor 

does not need to approve the unit 

operating agreement. 

(f) Extension of a lease covered by 

unit operations. If your unit agreement 

expires or terminates, or the unit area 

adjusts so that no part of your lease 

remains within the unit boundaries, 

your lease expires unless: 

(1) Its initial term has not expired; 

(2) You conduct drilling, production, 

or well-reworking operations on your 

lease consistent with applicable 

regulations; or 

(3) BSEE orders or approves a 

suspension of production or operations 

for your lease. 

(g) Unit operations. If your lease, or 

any part of your lease, is subject to a 

unit agreement, the entire lease 

continues for the term provided in the 

lease, and as long thereafter as any 

portion of your lease remains part of the 

unit area, and as long as operations 

continue the unit in effect. 

(1) If you drill, produce or perform 

well-workover operations on a lease 

within a unit, each lease, or part of a 

lease, in the unit will remain active in 

accordance with the unit agreement. 

Following a discovery, if your unit 

ceases drilling activities for a reasonable 

time period between the delineation of 

one or more reservoirs and the initiation 

of actual development drilling or 

production operations and that time 

period would extend beyond your 

lease’s primary term or any extension 

under § 250.180, the unit operator must 

request and obtain BSEE approval of a 

suspension of production under 

§ 250.170 in order to keep the unit from 

terminating. 

(2) When a lease in a unit agreement 

is beyond the primary term and the 

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 penalty 

was assessed, that you want your leasespecific/area-wide bond on file to be 

used as the bond for the penalty 

amount. 

(c) If you choose the alternative in 

paragraph (b)(2) of this section, the 

BOEM Regional Director may require 

additional security (i.e., security in 

excess of your existing bond) to ensure 

sufficient coverage during an appeal. In 

that event, the Regional Director will 

require you to post the supplemental 

bond with the regional office in the 

same manner as under 30 CFR 556.53(d) 

through (f). If the Regional Director 

determines the appeal should be 

covered by a lease-specific 

abandonment account then you must 

establish an account that meets the 

requirements of 30 CFR part 556.56. 

(d) If you do not either pay the 

penalty or file a timely appeal, BSEE 

will take one or more of the following 

actions: 

(1) We will collect the amount you 

were assessed, plus interest, late 

payment charges, and other fees as 

provided by law, from the date you 

received the Reviewing Officer’s final 

decision until the date we receive 

payment; 

(2) We may initiate additional 

enforcement, including, if appropriate, 

cancellation of the lease, right-of-way, 

license, permit, or approval, or the 

forfeiture of a bond under this part; or 

(3) We may bar you from doing 

further business with the Federal 

Government according to Executive 

Orders 12549 and 12689, and section 

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 when 

conducting well-drilling, wellcompletion, well-workover, or 

production operations. 

(a) Equipment movement. The 

movement of well-drilling, wellcompletion, or well-workover rigs and 

related equipment on and off an 

offshore platform, or from one well to 

another well on the same offshore 

platform, including rigging up and 

rigging down, shall be conducted in a 

safe manner. 

(b) Hydrogen sulfide (H2S). When a 

drilling, well-completion, wellworkover, or production operation is 

being conducted on a well in zones 

known to contain H2S or in zones where 

the presence of H2S is unknown (as 

defined in § 250.490 of this part), the 

lessee shall take appropriate precautions 

to protect life and property, especially 

during operations such as dismantling 

wellhead equipment and flow lines and 

circulating the well. The lessee shall 

also take appropriate precautions when 

H2S is generated as a result of sulphur 

production operations. The lessee shall 

comply with the requirements in 

§ 250.490 of this part as well as the 

requirements of this subpart. 

(c) Welding and burning practices and 

procedures. All welding, burning, and 

hot-tapping activities involved in 

drilling, well-completion, wellworkover or production operations shall 

be conducted with properly maintained 

equipment, trained personnel, and 

appropriate procedures in order to 

minimize the danger to life and property 

according to the specific requirements 

in §§ 250.109 through 250.113 of this 

part. 

(d) Electrical requirements. All 

electrical equipment and systems 

involved in drilling, well-completion, 

well-workover, and production 

operations shall be designed, installed, 

equipped, protected, operated, and 

maintained so as to minimize the danger 

to life and property in accordance with 

the requirements of § 250.114 of this 

part. 

(e) Structures on fixed OCS platforms. 

Derricks, cranes, masts, substructures, 

and related equipment shall be selected, 

designed, installed, used, and 

maintained so as to be adequate for the 

potential loads and conditions of 

loading that may be encountered during 

the operations. Prior to moving 

equipment such as a well-drilling, wellcompletion, or well-workover rig or 

associated equipment or production 

equipment onto a platform, the lessee 

shall determine the structural capability 

of the platform to safely support the 

equipment and operations, taking into 

consideration corrosion protection, 

platform age, and previous stresses. 

(f) Traveling-block safety device. All 

drilling units being used for drilling, 

well-completion, or well-workover 

operations that have both a traveling 

block and a crown block must be 

equipped with a safety device that is 

designed to prevent the traveling block 

from striking the crown block. The 

device must be checked for proper 

operation weekly and after each drillline slipping operation. The results of 

the operational check must be entered 

in the operations log. 

§ 250.1605 Drilling requirements. 

(a) Sulphur leases. Lessees of OCS 

sulphur leases shall conduct drilling 

operations in accordance with 

§§ 250.1605 through 250.1619 of this 

subpart and with other requirements of 

this part, as appropriate. 

(b) Fitness of drilling unit. (1) Drilling 

units shall be capable of withstanding 

the oceanographic and meteorological 

conditions for the proposed season and 

location of operations. 

(2) Prior to commencing operation, 

drilling units shall be made available for 

a complete inspection by the District 

Manager. 

(3) The lessee shall provide 

information and data on the fitness of 

the drilling unit to perform the 

proposed drilling operation. The 

information shall be submitted with, or 

prior to, the submission of Form BSEE– 

0123, Application for Permit to Drill 

(APD), in accordance with § 250.1617 of 

this subpart. After a drilling unit has 

been approved by a BSEE district office, 

the information required in this 

paragraph need not be resubmitted 

unless required by the District Manager 

or there are changes in the equipment 

that affect the rated capacity of the unit. 

(c) Oceanographic, meteorological, 

and drilling unit performance data. 

Where oceanographic, meteorological, 

and drilling unit performance data are 

not otherwise readily available, lessees 

shall collect and report such data upon 

request to the District Manager. The 

type of information to be collected and 

reported will be determined by the 

District Manager in the interests of 

safety in the conduct of operations and 

the structural integrity of the drilling 

unit. 

(d) Foundation requirements. When 

the lessee fails to provide sufficient 

information pursuant to 30 CFR 550.211 

through 550.228 and 30 CFR 550.241 

through 550.262 to support a 

determination that the seafloor is 

capable of supporting a specific bottomfounded drilling unit under the sitespecific soil and oceanographic 

conditions, the District Manager may 

require that additional surveys and soil 

borings be performed and the results 

submitted for review and evaluation by 

the District Manager before approval is 

granted for commencing drilling 

operations. 

(e) Tests, surveys, and samples. (1) 

Lessees shall drill and take cores and/ 

or run well and mud logs through the 

objective interval to determine the 

presence, quality, and quantity of 

sulphur and other minerals (e.g., oil and 

gas) in the cap rock and the outline of 

the commercial sulphur deposit. 

(2) Inclinational surveys shall be 

obtained on all vertical wells at 

intervals not exceeding 1,000 feet 

during the normal course of drilling. 

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Directional surveys giving both 

inclination and azimuth shall be 

obtained on all directionally drilled 

wells at intervals not exceeding 500 feet 

during the normal course of drilling and 

at intervals not exceeding 200 feet in all 

planned angle-change portions of the 

borehole. 

(3) Directional surveys giving both 

inclination and azimuth shall be 

obtained on both vertically and 

directionally drilled wells at intervals 

not exceeding 500 feet prior to or upon 

setting a string of casing, or production 

liner, and at total depth. Composite 

directional surveys shall be prepared 

with the interval shown from the bottom 

of the conductor casing. In calculating 

all surveys, a correction from the true 

north to Universal-Transverse-MercatorGrid-north or Lambert-Grid-north shall 

be made after making the magnetic-totrue-north correction. A composite 

dipmeter directional survey or a 

composite measurement while-drilling 

directional survey will be acceptable as 

fulfilling the applicable requirements of 

this paragraph. 

(4) Wells are classified as vertical if 

the calculated average of inclination 

readings weighted by the respective 

interval lengths between readings from 

surface to drilled depth does not exceed 

3 degrees from the vertical. When the 

calculated average inclination readings 

weighted by the length of the respective 

interval between readings from the 

surface to drilled depth exceeds 3 

degrees, the well is classified as 

directional. 

(5) At the request of a holder of an 

adjoining lease, the Regional Supervisor 

may, for the protection of correlative 

rights, furnish a copy of the directional 

survey to that leaseholder. 

(f) Fixed drilling platforms. 

Applications for installation of fixed 

drilling platforms or structures 

including artificial islands shall be 

submitted in accordance with the 

provisions of subpart I, Platforms and 

Structures, of this part. Mobile drilling 

units that have their jacking equipment 

removed or have been otherwise 

immobilized are classified as fixed 

bottom founded drilling platforms. 

(g) Crane operations. You must 

operate a crane installed on fixed 

platforms according to § 250.108 of this 

subpart. 

(h) Diesel-engine air intakes. Dieselengine air intakes must be equipped 

with a device to shut down the diesel 

engine in the event of runaway. Diesel 

engines that are continuously attended 

must be equipped with either remoteoperated manual or automaticshutdown devices. Diesel engines that 

are not continuously attended must be 

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: 

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(i) A kelly cock (an essentially fullopening valve) installed below the 

swivel and a similar valve of such 

design that it can be run through the 

BOP stack installed at the bottom of the 

kelly. A wrench to fit each valve shall 

be stored in a location readily accessible 

to the drilling crew; 

(ii) An inside BOP and an essentially 

full-opening, drill-string safety valve in 

the open position on the rig floor at all 

times while drilling operations are being 

conducted. These valves shall be 

maintained on the rig floor to fit all 

connections that are in the drill string. 

A wrench to fit the drill-string safety 

valve shall be stored in a location 

readily accessible to the drilling crew; 

(iii) A safety valve available on the rig 

floor assembled with the proper 

connection to fit the casing string being 

run in the hole; and 

(iv) Locking devices installed on the 

ram-type preventers. 

(e) BOP requirements. Prior to drilling 

below cap rock casing, a BOP system 

shall be installed consisting of at least 

three remote-controlled, hydraulically 

operated BOP’s including at least one 

equipped with pipe rams, one with 

blind rams, and one annular type. 

(f) Tapered drill-string operations. 

Prior to commencing tapered drill-string 

operations, the BOP stack shall be 

equipped with conventional and/or 

variable-bore pipe rams to provide 

either of the following: 

(1) One set of variable bore rams 

capable of sealing around both sizes in 

the string and one set of blind rams, or 

(2) One set of pipe rams capable of 

sealing around the larger size string, 

provided that blind-shear ram capability 

is present, and crossover subs to the 

larger size pipe are readily available on 

the rig floor. 

§ 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 

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lines instead of rigid pipe if the flexible 

hose has integral end couplings. The 

entire diverter system shall be firmly 

anchored and supported to prevent 

whipping and vibrations. All diverter 

control equipment and lines shall be 

protected from physical damage from 

thrown and falling objects. 

(c) For drilling operations conducted 

with a surface wellhead configuration, 

the following shall apply: 

(1) If the diverter system utilizes only 

one spool outlet, branch lines shall be 

installed to provide downwind 

diversion capability, and 

(2) No spool outlet or diverter line 

internal diameter shall be less than 10 

inches, except that dual spool outlets 

are acceptable if each outlet has a 

minimum internal diameter of 8 inches, 

and both outlets are piped to overboard 

lines and that each line downstream of 

the changeover nipple at the spool has 

a minimum internal diameter of 10 

inches. 

(d) The diverter sealing element and 

diverter valves shall be pressure tested 

to a minimum of 200 psi when nippled 

upon conductor casing. No more than 7 

days shall elapse between subsequent 

pressure tests. The diverter sealing 

element, diverter valves, and diverter 

control systems (including the remote) 

shall be actuation tested, and the 

diverter lines shall be tested for flow 

prior to spudding and thereafter at least 

once each 24-hour period alternating 

between control stations. All test times 

and results shall be recorded in the 

driller’s report. 

§ 250.1614 Mud program. 

(a) The quantities, characteristics, use, 

and testing of drilling mud and the 

related drilling procedures shall be 

designed and implemented to prevent 

the loss of well control. 

(b) The lessee shall comply with 

requirements concerning mud control, 

mud test and monitoring equipment, 

mud quantities, and safety precautions 

in enclosed mud handling areas as 

prescribed in §§ 250.455 through 

250.459 of this part, except that the 

installation of an operable degasser in 

the mud system as required in 

§ 250.456(g) is not required for sulphur 

operations. 

§ 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, 

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(ii) Estimated depths to the top of 

significant marker formations, and 

(iii) Estimated depths at which 

encounters with fresh water, sulphur, 

oil, gas, or abnormally pressured water 

are expected. 

(6) A cementing program including 

type and amount of cement in cubic feet 

to be used for each casing string; 

(7) A mud program including the 

minimum quantities of mud and mud 

materials, including weight materials, to 

be kept at the site; 

(8) A directional survey program for 

directionally drilled wells; 

(9) An H2S Contingency Plan, if 

applicable, and if not previously 

submitted; and 

(10) Such other information as may be 

required by the District Manager. 

(d) Public information copies of the 

APD shall be submitted in accordance 

with § 250.186 of this part. 

§ 250.1618 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 wellworkover requirements. 

(a) Lessees shall conduct wellcompletion and well-workover 

operations in sulphur wells, bleedwells, 

and brine wells in accordance with 

§§ 250.1620 through 250.1626 of this 

part and other provisions of this part as 

appropriate (see §§ 250.501 and 250.601 

of this part for the definition of wellcompletion and well-workover 

operations). 

(b) Well-completion and wellworkover operations shall be conducted 

in a manner to protect against harm or 

damage to life (including fish and other 

aquatic life), property, natural resources 

of the OCS including any mineral 

deposits (in areas leased and not 

leased), the National security or defense, 

or the marine, coastal, or human 

environment. 

§ 250.1621 Crew instructions. 

Prior to engaging in well-completion 

or well-workover operations, crew 

members shall be instructed in the 

safety requirements of the operations to 

be performed, possible hazards to be 

encountered, and general safety 

considerations to protect personnel, 

equipment, and the environment. Date 

and time of safety meetings shall be 

recorded and available for BSEE review. 

§ 250.1622 Approvals and reporting of 

well-completion and well-workover 

operations. 

(a) No well-completion or wellworkover operation shall begin until the 

lessee receives written approval from 

the District Manager. Approval for such 

operations shall be requested on Form 

BSEE–0124. Approvals by the District 

Manager shall be based upon a 

determination that the operations will 

be conducted in a manner to protect 

against harm or damage to life, property, 

natural resources of the OCS, including 

any mineral deposits, the National 

security or defense, or the marine, 

coastal, or human environment. 

(b) The following information shall be 

submitted with Form BSEE–0124 (or 

with Form BSEE–0123): 

(1) A brief description of the wellcompletion or well-workover 

procedures to be followed; 

(2) When changes in existing 

subsurface equipment are proposed, a 

schematic drawing showing the well 

equipment; and 

(3) Where the well is in zones known 

to contain H2S or zones where the 

presence of H2S is unknown, a 

description of the safety precautions to 

be implemented. 

(c)(1) Within 30 days after 

completion, Form BSEE–0125, 

including a schematic of the tubing and 

the results of any well tests, shall be 

submitted to the District Manager. 

(2) Within 30 days after completing 

the well-workover operation, except 

routine operations, Form BSEE–0124 

shall be submitted to the District 

Manager and shall include the results of 

any well tests and a new schematic of 

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the well if any subsurface equipment 

has been changed. 

§ 250.1623 Well-control fluids, equipment, 

and operations. 

(a) Well-control fluids, equipment, 

and operations shall be designed, 

utilized, maintained, and/or tested as 

necessary to control the well in 

foreseeable conditions and 

circumstances, including subfreezing 

conditions. The well shall be 

continuously monitored during wellcompletion and well-workover 

operations and shall not be left 

unattended at any time unless the well 

is shut in and secured; 

(b) The following well-control fluid 

equipment shall be installed, 

maintained, and utilized: 

(1) A fill-up line above the uppermost 

BOP, 

(2) A well-control fluid-volume 

measuring device for determining fluid 

volumes when filling the hole on trips, 

and 

(3) A recording mud-pit-level 

indicator to determine mud-pit-volume 

gains and losses. This indicator shall 

include both a visual and an audible 

warning device. 

(c) When coming out of the hole with 

drill pipe or a workover string, the 

annulus shall be filled with well-control 

fluid before the change in fluid level 

decreases the hydrostatic pressure 75 

psi or every five stands of drill pipe or 

workover string, whichever gives a 

lower decrease in hydrostatic pressure. 

The number of stands of drill pipe or 

workover string and drill collars that 

may be pulled prior to filling the hole 

and the equivalent well-control fluid 

volume shall be calculated and posted 

near the operator’s station. A 

mechanical, volumetric, or electronic 

device for measuring the amount of 

well-control fluid required to fill the 

hole shall be utilized. 

§ 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 11⁄4

inch) as a work string; i.e., small-tubing 

operations, shall consist of the 

following: 

(1) For air line changes, the well shall 

be killed prior to beginning operations. 

The procedures for killing the well shall 

be included in the description of wellworkover procedures in accordance 

with § 250.1622 of this part. Under these 

circumstances, no BOP equipment is 

required. 

(2) For other work inside of the 

sulphur line, a tubing stripper or 

annular preventer shall be installed 

prior to beginning work. 

(e) An essentially full-opening, workstring safety valve shall be maintained 

on the rig floor at all times during wellcompletion operations. A wrench to fit 

the work-string safety valve shall be 

readily available. Proper connections 

shall be readily available for inserting a 

safety valve in the work string. 

§ 250.1625 Blowout preventer system 

testing, records, and drills. 

(a) Prior to conducting high-pressure 

tests, all BOP systems shall be tested to 

a pressure of 200 to 300 psi. 

(b) Ram-type BOP’s and the choke 

manifold shall be pressure tested with 

water to a rated working pressure or as 

otherwise approved by the District 

Manager. Annular type BOP’s shall be 

pressure tested with water to 70 percent 

of rated working pressure or as 

otherwise approved by the District 

Manager. 

(c) In conjunction with the weekly 

pressure test of BOP systems required in 

paragraph (d) of this section, the choke 

manifold valves, upper and lower kelly 

cocks, and drill-string safety valves shall 

be pressure tested to pipe-ram test 

pressures. Safety valves with proper 

casing connections shall be actuated 

prior to running casing. 

(d) BOP system shall be pressure 

tested as follows: 

(1) When installed; 

(2) Before drilling out each string of 

casing or before continuing operations 

in cases where cement is not drilled out; 

(3) At least once each week, but not 

exceeding 7 days between pressure 

tests, alternating between control 

stations. If either control system is not 

functional, further drilling operations 

shall be suspended until that system 

becomes operable. A period of more 

than 7 days between BOP tests is 

allowed when there is a stuck drill pipe 

or there are pressure control operations, 

and remedial efforts are being 

performed, provided that the pressure 

tests are conducted as soon as possible 

and before normal operations resume. 

The time, date, and reason for 

postponing pressure testing shall be 

entered into the driller’s report. Pressure 

testing shall be performed at intervals to 

allow each drilling crew to operate the 

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equipment. The weekly pressure test is 

not required for blind and blind-shear 

rams; 

(4) Blind and blind-shear rams shall 

be actuated at least once every 7 days. 

Closing pressure on the blind and blindshear rams greater than necessary to 

indicate proper operation of the rams is 

not required; 

(5) Variable bore-pipe rams shall be 

pressure tested against all sizes of pipe 

in use, excluding drill collars and 

bottomhole tools; and 

(6) Following the disconnection or 

repair of any well-pressure containment 

seal in the wellhead/BOP stack 

assembly, the pressure tests may be 

limited to the affected component. 

(e) All personnel engaged in wellcompletion operations shall participate 

in a weekly BOP drill to familiarize 

crew members with appropriate safety 

measures. 

(f) The lessee shall record pressure 

conditions during BOP tests on pressure 

charts, unless otherwise approved by 

the District Manager. The test duration 

for each BOP component tested shall be 

sufficient to demonstrate that the 

component is effectively holding 

pressure. The charts shall be certified as 

correct by the operator’s representative 

at the facility. 

(g) The time, date, and results of all 

pressure tests, actuations, inspections, 

and crew drills of the BOP system and 

system components shall be recorded in 

the operations log. The BOP tests shall 

be documented in accordance with the 

following: 

(1) The documentation shall indicate 

the sequential order of BOP and 

auxiliary equipment testing and the 

pressure and duration of each test. As 

an alternate, the documentation in the 

operations log may reference a BOP test 

plan that contains the required 

information and is retained on file at the 

facility. 

(2) The control station used during 

the test shall be identified in the 

operations log. 

(3) Any problems or irregularities 

observed during BOP and auxiliary 

equipment testing and any actions taken 

to remedy such problems or 

irregularities shall be noted in the 

operations log. 

(4) Documentation required to be 

entered in the driller’s report may 

instead be referenced in the driller’s 

report. All records, including pressure 

charts, driller’s report, and referenced 

documents, pertaining to BOP tests, 

actuations, and inspections shall be 

available for BSEE review at the facility 

for the duration of the drilling activity. 

Following completion of the drilling 

activity, all drilling records shall be 

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 

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pumps, metering devices, and other 

hydrocarbon-handling vessels; 

(2) A schematic flow diagram (API RP 

14C, Figure E1, as incorporated by 

reference in § 250.198) and the related 

Safety Analysis Function Evaluation 

chart (API RP 14C, subsection 4.3c, as 

incorporated by reference in § 250.198). 

(3) A schematic piping diagram 

showing the size and maximum 

allowable working pressures as 

determined in accordance with API RP 

14E, Design and Installation of Offshore 

Production Platform Piping Systems (as 

incorporated by reference in § 250.198); 

(4) Electrical system information 

including the following: 

(i) A plan of each platform deck, 

outlining all hazardous areas classified 

according to API RP 500, Recommended 

Practice for Classification of Locations 

for Electrical Installations at Petroleum 

Facilities Classified as Class I, Division 

1 and Division 2, or API RP 505, 

Recommended Practice for 

Classification of Locations for Electrical 

Installations at Petroleum Facilities 

Classified as Class I, Zone 0, Zone 1, 

and Zone 2 (as incorporated by 

reference in § 250.198), and outlining 

areas in which potential ignition 

sources are to be installed; 

(ii) All significant hydrocarbon 

sources and a description of the type of 

decking, ceiling, walls (e.g., grating or 

solid), and firewalls; and 

(iii) Elementary electrical schematic 

of any platform safety shutdown system 

with a functional legend. 

(5) Certification that the design for the 

mechanical and electrical systems to be 

installed was approved by registered 

professional engineers. After these 

systems are installed, the lessee shall 

submit a statement to the District 

Manager certifying that the new 

installations conform to the approved 

designs of this subpart; and 

(6) Design and schematics of the 

installation and maintenance of all fireand gas-detection systems including the 

following: 

(i) Type, location, and number of 

detection heads; 

(ii) Type and kind of alarm, including 

emergency equipment to be activated; 

(iii) Method used for detection; 

(iv) Method and frequency of 

calibration; and 

(v) A functional block diagram of the 

detection system, including the electric 

power supply. 

§ 250.1629 Additional production and fuel 

gas system requirements. 

(a) General. Lessees shall comply with 

the following production safety system 

requirements (some of which are in 

addition to those contained in 

§ 250.1628 of this part). 

(b) Design, installation, and operation 

of additional production systems, 

including fuel gas handling safety 

systems. (1) Pressure and fired vessels 

must be designed, fabricated, and code 

stamped in accordance with the 

applicable provisions of sections I, IV, 

and VIII of the American Society of 

Mechanical Engineers (ASME) Boiler 

and Pressure Vessel Code (as specified 

in § 250.198). Pressure and fired vessels 

must have maintenance inspection, 

rating, repair, and alteration performed 

in accordance with the applicable 

provisions of API Pressure Vessel 

Inspections Code: In-Service Inspection, 

Rating, Repair, and Alteration, API 510 

(except Sections 5.8 and 9.5) (as 

incorporated by reference in § 250.198). 

(i) Pressure safety relief valves shall 

be designed, installed, and maintained 

in accordance with applicable 

provisions of sections I, IV, and VIII of 

the ANSI/ASME Boiler and Pressure 

Vessel Code (as specified in § 250.198). 

The safety relief valves shall conform to 

the valve-sizing and pressure-relieving 

requirements specified in these 

documents; however, the safety relief 

valves shall be set no higher than the 

maximum-allowable working pressure 

of the vessel. All safety relief valves and 

vents shall be piped in such a way as 

to prevent fluid from striking personnel 

or ignition sources. 

(ii) The lessee shall use pressure 

recorders to establish the operating 

pressure ranges of pressure vessels in 

order to establish the pressure-sensor 

settings. Pressure-recording charts used 

to determine operating pressure ranges 

shall be maintained by the lessee for a 

period of 2 years at the lessee’s field 

office nearest the OCS facility or at 

another location conveniently available 

to the District Manager. The highpressure sensor shall be set no higher 

than 15 percent or 5 psi, whichever is 

greater, above the highest operating 

pressure of the vessel. This setting shall 

also be set sufficiently below (15 

percent or 5 psi, whichever is greater) 

the safety relief valve’s set pressure to 

assure that the high-pressure sensor 

sounds an alarm before the safety relief 

valve starts relieving. The low-pressure 

sensor shall sound an alarm no lower 

than 15 percent or 5 psi, whichever is 

greater, below the lowest pressure in the 

operating range. 

(2) Engine exhaust. You must equip 

engine exhausts to comply with the 

insulation and personnel protection 

requirements of API RP 14C, section 

4.2c(4) (as incorporated by reference in 

§ 250.198). Exhaust piping from diesel 

engines must be equipped with spark 

arresters. 

(3) Firefighting systems. Firefighting 

systems must conform to subsection 5.2, 

Fire Water Systems, of API RP 14G, 

Recommended Practice for Fire 

Prevention and Control on Open Type 

Offshore Production Platforms (as 

incorporated by reference in § 250.198), 

and must be subject to the approval of 

the District Manager. Additional 

requirements must apply as follows: 

(i) A firewater system consisting of 

rigid pipe with firehose stations shall be 

installed. The firewater system shall be 

installed to provide needed protection, 

especially in areas where fuel handling 

equipment is located. 

(ii) Fuel or power for firewater pump 

drivers shall be available for at least 30 

minutes of run time during platform 

shut-in time. If necessary, an alternate 

fuel or power supply shall be installed 

to provide for this pump-operating time 

unless an alternate firefighting system 

has been approved by the District 

Manager; 

(iii) A firefighting system using 

chemicals may be used in lieu of a water 

system if the District Manager 

determines that the use of a chemical 

system provides equivalent fireprotection control; and 

(iv) A diagram of the firefighting 

system showing the location of all 

firefighting equipment shall be posted 

in a prominent place on the facility or 

structure. 

(4) Fire- and gas-detection system. (i) 

Fire (flame, heat, or smoke) sensors 

shall be installed in all enclosed 

classified areas. Gas sensors shall be 

installed in all inadequately ventilated, 

enclosed classified areas. Adequate 

ventilation is defined as ventilation that 

is sufficient to prevent accumulation of 

significant quantities of vapor-air 

mixture in concentrations over 25 

percent of the lower explosive limit. 

One approved method of providing 

adequate ventilation is a change of air 

volume each 5 minutes or 1 cubic foot 

of air-volume flow per minute per 

square foot of solid floor area, 

whichever is greater. Enclosed areas 

(e.g., buildings, living quarters, or 

doghouses) are defined as those areas 

confined on more than four of their six 

possible sides by walls, floors, or 

ceilings more restrictive to air flow than 

grating or fixed open louvers and of 

sufficient size to allow entry of 

personnel. A classified area is any area 

classified Class I, Group D, Division 1 or 

2, following the guidelines of API RP 

500 (as incorporated by reference in 

§ 250.198), or any area classified Class I, 

Zone 0, Zone 1, or Zone 2, following the 

guidelines of API RP 505 (as 

incorporated by reference in § 205.198). 

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(ii) All detection systems shall be 

capable of continuous monitoring. Firedetection systems and portions of 

combustible gas-detection systems 

related to the higher gas concentration 

levels shall be of the manual-reset type. 

Combustible gas-detection systems 

related to the lower gas-concentration 

level may be of the automatic-reset type. 

(iii) A fuel-gas odorant or an 

automatic gas-detection and alarm 

system is required in enclosed, 

continuously manned areas of the 

facility that are provided with fuel gas. 

Living quarters and doghouses not 

containing a gas source and not located 

in a classified area do not require a gas 

detection system. 

(iv) The District Manager may require 

the installation and maintenance of a 

gas detector or alarm in any potentially 

hazardous area. 

(v) Fire- and gas-detection systems 

must be an approved type, designed and 

installed according to API RP 14C, API 

RP 14G, and either API RP 14F or API 

RP 14FZ (the preceding four documents 

as incorporated by reference in 

§ 250.198). 

(c) General platform operations. 

Safety devices shall not be bypassed or 

blocked out of service unless they are 

temporarily out of service for startup, 

maintenance, or testing procedures. 

Only the minimum number of safety 

devices shall be taken out of service. 

Personnel shall monitor the bypassed or 

blocked out functions until the safety 

devices are placed back in service. Any 

safety device that is temporarily out of 

service shall be flagged by the person 

taking such device out of service. 

§ 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, 

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platforms, templates, pilings, pipelines, 

pipeline valves, and power cables. 

(c) Facility means any installation 

other than a pipeline used for oil, gas, 

or sulphur activities that is permanently 

or temporarily attached to the seabed on 

the OCS. Facilities include production 

and pipeline risers, templates, pilings, 

and any other facility or equipment that 

constitutes an obstruction such as 

jumper assemblies, termination skids, 

umbilicals, anchors, and mooring lines. 

§ 250.1701 Who must meet the 

decommissioning obligations in this 

subpart? 

(a) Lessees and owners of operating 

rights are jointly and severally 

responsible for meeting 

decommissioning obligations for 

facilities on leases, including the 

obligations related to lease-term 

pipelines, as the obligations accrue and 

until each obligation is met. 

(b) All holders of a right-of-way are 

jointly and severally liable for meeting 

decommissioning obligations for 

facilities on their right-of-way, 

including right-of-way pipelines, as the 

obligations accrue and until each 

obligation is met. 

(c) In this subpart, the terms ‘‘you’’ or 

‘‘I’’ refer to lessees and owners of 

operating rights, as to facilities installed 

under the authority of a lease, and to 

right-of-way holders as to facilities 

installed under the authority of a rightof-way. 

§ 250.1702 When do I accrue 

decommissioning obligations? 

You accrue decommissioning 

obligations when you do any of the 

following: 

(a) Drill a well; 

(b) Install a platform, pipeline, or 

other facility; 

(c) Create an obstruction to other 

users of the OCS; 

(d) Are or become a lessee or the 

owner of operating rights of a lease on 

which there is a well that has not been 

permanently plugged according to this 

subpart, a platform, a lease term 

pipeline, or other facility, or an 

obstruction; 

(e) Are or become the holder of a 

pipeline right-of-way on which there is 

a pipeline, platform, or other facility, or 

an obstruction; or 

(f) Re-enter a well that was previously 

plugged according to this subpart. 

§ 250.1703 What are the general 

requirements for decommissioning? 

When your facilities are no longer 

useful for operations, you must: 

(a) Get approval from the appropriate 

District Manager before 

decommissioning wells and from the 

Regional Supervisor before 

decommissioning platforms and 

pipelines or other facilities; 

(b) Permanently plug all wells; 

(c) Remove all platforms and other 

facilities, except as provided in 

§§ 250.1725(a) and 250.1730. 

(d) Decommission all pipelines; 

(e) Clear the seafloor of all 

obstructions created by your lease and 

pipeline right-of-way operations; and 

(f) Conduct all decommissioning 

activities in a manner that is safe, does 

not unreasonably interfere with other 

uses of the OCS, and does not cause 

undue or serious harm or damage to the 

human, marine, or coastal environment. 

§ 250.1704 When must I submit 

decommissioning applications and reports? 

You must submit decommissioning 

applications and receive approval and 

submit subsequent reports according to 

the table in this section. 

DECOMMISSIONING APPLICATIONS AND REPORTS TABLE

Decommissioning applications and reports When to submit Instructions 

(a) Initial platform removal application [not required in 

the Gulf of Mexico OCS Region].

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 2 

years 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 information 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 information 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. 

PERMANENT WELL PLUGGING REQUIREMENTS

If you have . . . Then you must use . . . 

(1) Zones in open hole, Cement plug(s) set from at least 100 feet below the bottom to 100 feet above the top of oil, 

gas, and fresh-water zones to isolate fluids in the strata.

(2) Open hole below casing, (i) A cement plug, set by the displacement method, at least 100 feet above and below deepest casing shoe; 

(ii) A cement retainer with effective back-pressure control set 50 to 100 feet above the casing 

shoe, and a cement plug that extends at least 100 feet below the casing shoe and at least 

50 feet above the retainer; or 

(iii) A bridge plug set 50 feet to 100 feet above the shoe with 50 feet of cement on top of the 

bridge plug, for expected or known lost circulation conditions.

(3) A perforated zone that is currently open 

and 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; 

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PERMANENT WELL PLUGGING REQUIREMENTS—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 alternate 

requirements 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 

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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 location. 

(b) You must trawl 100 percent of the 

limits described in paragraph (a) of this 

section in two directions. 

(c) You must mark the area to be 

cleared as a hazard to navigation 

according to USCG requirements until 

you complete the site clearance 

procedures. 

(d) You must use a trawling vessel 

equipped with a calibrated navigational 

positioning system capable of providing 

position accuracy of ±30 feet. 

(e) You must use a trawling net that 

is representative of those used in the 

commercial fishing industry (one that 

has a net strength equal or greater than 

that provided by No. 18 twine). 

(f) You must ensure that you trawl no 

closer than 300 feet from a shipwreck, 

and 500 feet from a sensitive biological 

feature. 

(g) If you trawl near an active 

pipeline, you must meet the 

requirements in the following table: 

For . . . You must trawl . . . And you must . . . 

(1) Buried active pipelines, First contact the pipeline owner or operator to 

determine the condition of the pipeline before trawling over the buried pipeline. 

(2) Unburied active pipelines that are 8 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. 

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§ 250.1743 How do I certify that a site is 

clear of obstructions? 

(a) For a well site, you must submit 

to the appropriate District Manager 

within 30 days after you complete the 

verification activities a form BSEE– 

0124, Application for Permit to Modify, 

to include the following information: 

(1) A signed certification that the well 

site area is cleared of all obstructions; 

(2) The date the verification work was 

performed and the vessel used; 

(3) The extent of the area surveyed; 

(4) The survey method used; 

(5) The results of the survey, 

including a list of any debris removed 

or a statement from the trawling 

contractor that no objects were 

recovered; and 

(6) A post-trawling job plot or map 

showing the trawled area. 

(b) For a platform or other facility site, 

you must submit the following 

information to the appropriate Regional 

Supervisor within 30 days after you 

complete the verification activities: 

(1) A letter signed by an authorized 

company official certifying that the 

platform or other facility site area is 

cleared of all obstructions and that a 

company representative witnessed the 

verification activities; 

(2) A letter signed by an authorized 

official of the company that performed 

the verification work for you certifying 

that it cleared the platform or other 

facility site area of all obstructions; 

(3) The date the verification work was 

performed and the vessel used; 

(4) The extent of the area surveyed; 

(5) The survey method used; 

(6) The results of the survey, 

including a list of any debris removed 

or a statement from the trawling 

contractor that no objects were 

recovered; and 

(7) A post-trawling job plot or map 

showing the trawled area. 

Pipeline Decommissioning 

§ 250.1750 When may I decommission a 

pipeline in place? 

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. 

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(b) All personnel involved with your 

SEMS program must be trained to have 

the skills and knowledge to perform 

their assigned duties. 

§ 250.1902 What must I include in my 

SEMS program? 

You must have a properly 

documented SEMS program in place 

and make it available to BSEE upon 

request as required by § 250.1924(b). 

(a) Your SEMS program must meet the 

minimum criteria outlined in this 

subpart, including the following SEMS 

program elements: 

(1) General (see § 250.1909) 

(2) Safety and Environmental 

Information (see § 250.1910) 

(3) Hazards Analysis (see § 250.1911) 

(4) Management of Change (see 

§ 250.1912) 

(5) Operating Procedures (see 

§ 250.1913) 

(6) Safe Work Practices (see 

§ 250.1914) 

(7) Training (see § 250.1915) 

(8) Mechanical Integrity (Assurance of 

Quality and Mechanical Integrity of 

Critical Equipment) (see § 250.1916) 

(9) Pre-startup Review (see 

§ 250.1917) 

(10) Emergency Response and Control 

(see § 250.1918) 

(11) Investigation of Incidents (see 

§ 250.1919) 

(12) Auditing (Audit of Safety and 

Environmental Management Program 

Elements) (see §§ 250.1920) 

(13) Recordkeeping (Records and 

Documentation) and additional BSEE 

requirements (see § 250.1928). 

(b) You must also include a job safety 

analysis (JSA) for OCS activities 

identified or discussed in your SEMS 

program (see § 250.1911(b)). 

(c) Your SEMS program must meet or 

exceed the standards of safety and 

environmental protection of API RP 75 

(as incorporated by reference in 

§ 250.198). 

§ 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; 

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floating production, storage and 

offloading facilities; tension-leg 

platforms; and spars) used for 

exploration, development, production, 

and transportation activities for oil, gas, 

or sulphur from areas leased in the OCS. 

Facilities also include DOI regulated 

pipelines. You must document and 

maintain current analyses for each 

operation covered by this section for the 

life of the operation at the facility. The 

analyses must be updated when an 

internal audit is conducted to ensure 

that it is consistent with the current 

operations on your facility. Hazards 

analysis requirements for simple and 

nearly identical facilities, such as well 

jackets and single well caissons, may be 

fulfilled by performing a single hazards 

analysis which you can apply to all 

such facilities after you verify that any 

site specific deviations are addressed in 

each of the elements of your SEMS 

program. 

(a) Hazards Analysis (facility level). 

For a hazards analysis (facility level), 

you must perform an initial hazards 

analysis on each facility on or before 

November 15, 2011. The hazards 

analysis must be appropriate to the 

complexity of the operation and must 

identify, evaluate, and manage the 

hazards involved in the operation. 

(1) The hazards analysis must address 

the following: 

(i) Hazards of the operation; 

(ii) Previous incidents related to the 

operation you are evaluating, including 

any incident in which you were issued 

an Incident of Noncompliance or a civil 

or criminal penalty; 

(iii) Control technology applicable to 

the operation your hazards analysis is 

evaluating; and 

(iv) A qualitative evaluation of the 

possible safety and health effects on 

employees, and potential impacts to the 

human and marine environments, 

which may result if the control 

technology fails. 

(2) The hazards analysis must be 

performed by a person(s) with 

experience in the operations being 

evaluated. These individuals also need 

to be experienced in the hazards 

analysis methodologies being employed. 

(3) You should assure that the 

recommendations in the hazards 

analysis are resolved and that the 

resolution is documented. 

(b) Job Safety Analysis (JSA). You 

must develop and implement a JSA for 

OCS activities identified or discussed in 

your SEMS program. 

(1) You must keep a copy of the most 

recent JSA (operations/task level) at the 

job site and it must be readily accessible 

to employees. 

(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 following 

qualifications when selecting the thirdparty or your designated and qualified 

personnel: 

(1) Previous education and experience 

with SEMS, or similar management 

related programs. 

(2) Technical capabilities of the 

individual or organization for the 

specific project. 

(3) Ability to perform the independent 

third-party functions for the specific 

project considering current 

commitments. 

(4) Previous experience with BSEE 

regulatory requirements and procedures. 

(5) Previous education and experience 

to comprehend and evaluate how the 

company’s offshore activities, raw 

materials, production methods and 

equipment, products, byproducts, and 

business management systems may 

impact health and safety performance in 

the workplace. 

(b) You must have procedures to 

avoid conflicts of interest related to the 

development of your SEMS program 

and the independent third party auditor 

and your designated and qualified 

personnel. 

(c) BSEE may evaluate the 

qualifications of the independent third 

parties or your designated and qualified 

personnel. This may include an audit of 

documents and procedures or 

interviews. BSEE may disallow audits 

by a specific independent third-party or 

your designated and qualified personnel 

if they do not meet the criteria of this 

section. 

§ 250.1927 What happens if BSEE finds 

shortcomings in my SEMS program? 

If BSEE determines that your SEMS 

program is not in compliance with this 

subpart we may initiate one or more of 

the following enforcement actions: 

(a) Issue an Incident(s) of 

Noncompliance; 

(b) Assess civil penalties; or 

(c) Initiate probationary or 

disqualification procedures from serving 

as an OCS operator. 

§ 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 the 

requirements 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 for 

use in coordinating and directing spillresponse operations. You must provide 

telephone numbers for the response 

operations center. You also must 

provide any facsimile numbers and 

primary and secondary radio 

frequencies that will be used. 

(e) A listing of the types and 

characteristics of the oil handled, 

stored, or transported at the facility. 

(f) Procedures for the early detection 

of a spill. 

(g) Identification of procedures you 

will follow in the event of a spill or a 

substantial threat of a spill. The 

procedures should show appropriate 

response levels for differing spill sizes 

including those resulting from a fire or 

explosion. These will include, as 

appropriate: 

(1) Your procedures for spill 

notification. The plan must provide for 

the use of the oil spill reporting forms 

included in the Area Contingency Plan 

or an equivalent reporting form. 

(i) Your procedures must include a 

current list which identifies the 

following by name or position, 

corporate address, and telephone 

number (including facsimile number if 

applicable): 

(A) The qualified individual; 

(B) The spill-response coordinator 

and alternate(s); and 

(C) Other spill-response management 

team members. 

(ii) You must also provide names, 

telephone numbers, and addresses for 

the following: 

(A) OSRO’s that the plan cites; 

(B) Federal, State, and local regulatory 

agencies that you must consult to obtain 

site specific environmental information; 

and 

(C) Federal, State, and local regulatory 

agencies that you must notify when an 

oil spill occurs. 

(2) Your methods to monitor and 

predict spill movement; 

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(3) Your methods to identify and 

prioritize the beaches, waterfowl, other 

marine and shoreline resources, and 

areas of special economic and 

environmental importance; 

(4) Your methods to protect beaches, 

waterfowl, other marine and shoreline 

resources, and areas of special economic 

or environmental importance; 

(5) Your methods to ensure that 

containment and recovery equipment as 

well as the response personnel are 

mobilized and deployed at the spill site; 

(6) Your methods to ensure that 

devices for the storage of recovered oil 

are sufficient to allow containment and 

recovery operations to continue without 

interruption; 

(7) Your procedures to remove oil and 

oiled debris from shallow waters and 

along shorelines and rehabilitating 

waterfowl which become oiled; 

(8) Your procedures to store, transfer, 

and dispose of recovered oil and oilcontaminated materials and to ensure 

that all disposal is in accordance with 

Federal, State, and local requirements; 

and 

(9) Your methods to implement your 

dispersant use plan and your in situ 

burning plan. 

§ 254.24 What information must I include 

in the ‘‘Equipment inventory’’ appendix? 

Your ‘‘Equipment inventory 

appendix’’ must include: 

(a) An inventory of spill-response 

materials and supplies, services, 

equipment, and response vessels 

available locally and regionally. You 

must identify each supplier and provide 

their locations and telephone numbers. 

(b) A description of the procedures for 

inspecting and maintaining spillresponse equipment in accordance with 

§ 254.43. 

§ 254.25 What information must I include 

in the ‘‘Contractual agreements’’ appendix? 

Your ‘‘Contractual agreements’’ 

appendix must furnish proof of any 

contracts or membership agreements 

with OSRO’s, cooperatives, spillresponse service providers, or spill 

management team members who are not 

your employees that you cite in the 

plan. To provide this proof, submit 

copies of the contracts or membership 

agreements or certify that contracts or 

membership agreements are in effect. 

The contract or membership agreement 

must include provisions for ensuring 

the availability of the personnel and/or 

equipment on a 24-hour-per-day basis. 

§ 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 may 

require performance testing of any spillresponse equipment listed in your 

response plan to verify its capabilities if 

the equipment: 

(1) Has been modified; 

(2) Has been damaged and repaired; or 

(3) Has a claimed effective daily 

recovery capacity that is inconsistent 

with data otherwise available to BSEE. 

(b) You must conduct any required 

performance testing of booms in 

accordance with BSEE-approved test 

criteria. You may use the document 

‘‘Test Protocol for the Evaluation of OilSpill Containment Booms,’’ available 

from BSEE, for guidance. Performance 

testing of skimmers also must be 

conducted in accordance with BSEE 

approved test criteria. You may use the 

document ‘‘Suggested Test Protocol for 

the Evaluation of Oil Spill Skimmers for 

the OCS,’’ available from BSEE, for 

guidance. 

(c) You are responsible for any 

required testing of equipment 

performance and for the accuracy of the 

information submitted. 

§ 254.46 Whom do I notify if an oil spill 

occurs? 

(a) You must immediately notify the 

National Response Center (1–800–424– 

8802) if you observe: 

(1) An oil spill from your facility; 

(2) An oil spill from another offshore 

facility; or 

(3) An offshore spill of unknown 

origin. 

(b) In the event of a spill of 1 barrel 

or more from your facility, you must 

orally notify the Regional Supervisor 

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 

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Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations 64613 

(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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64614 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations 

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: 

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Act means the OCS Lands Act, as 

amended (43 U.S.C. 1331 et seq.). 

Adjacent State means with respect to 

any activity proposed, conducted, or 

approved under this part, any coastal 

State: 

(1) That is, or is proposed to be, 

receiving for processing, refining, or 

transshipment OCS mineral resources 

commercially recovered from the 

seabed; 

(2) That is used, or is scheduled to be 

used, as a support base for prospecting, 

exploration, testing, or mining activities; 

or 

(3) In which there is a reasonable 

probability of significant effect on land 

or water uses from such activity. 

Contingency Plan means a plan for 

action to be taken in emergency 

situations. 

Data means geological and 

geophysical (G&G) facts and statistics or 

samples which have not been analyzed, 

processed, or interpreted. 

Development means those activities 

which take place following the 

discovery of minerals in paying 

quantities including geophysical 

activities, drilling, construction of 

offshore facilities, and operation of all 

onshore support facilities, which are for 

the purpose of ultimately producing the 

minerals discovered. 

Director means the Director of BSEE 

of the U.S. Department of the Interior or 

an official authorized to act on the 

Director’s behalf. 

Exploration means the process of 

searching for minerals on a lease 

including: 

(1) Geophysical surveys where 

magnetic, gravity, seismic, or other 

systems are used to detect or imply the 

presence of minerals; 

(2) Any drilling including the drilling 

of a borehole in which the discovery of 

a mineral other than oil, gas, or sulphur 

is made and the drilling of any 

additional boreholes needed to 

delineate any mineral deposits; and 

(3) The taking of sample portions of 

a mineral deposit to enable the lessee to 

determine whether to proceed with 

development and production. 

Geological sample means a collected 

portion of the seabed, the subseabed, or 

the overylying waters (when obtained 

for geochemical analysis) acquired 

while conducting postlease mining 

activities. 

Governor means the Governor of a 

State or the person or entity designated 

by, or pursuant to, State law to exercise 

the power granted to a Governor. 

Information means G&G data that 

have been analyzed, processed, or 

interpreted. 

Lease means one of the following, 

whichever is required by the context: 

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 

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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, 

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or requirement to modify such plans 

may take the form of a condition of 

granting a right of use and easement 

under paragraph (a) of this section or as 

authorized under any lease issued or 

maintained under the Act. 

(g) [Reserved] 

(h) The Director may prescribe or 

approve, in writing or orally, departures 

from the operating requirements of the 

regulations of this part when such 

departures are necessary to facilitate the 

proper development of a lease; to 

conserve natural resources; or to protect 

life (including fish and other aquatic 

life), property, or the marine, coastal, or 

human environment. 

§ 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 

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royalty free or subject to a reduced 

royalty obligation shall not be extended 

unless the Director’s approval of the 

suspension specifies otherwise. 

(3) If the lease anniversary date falls 

within a period of suspension for which 

no rental or minimum royalty payments 

are required under paragraph (a) of this 

section, the prorated rentals or 

minimum royalties are due and payable 

as of the date the suspension period 

terminates. These amounts shall be 

computed and notice thereof given the 

lessee. The lessee shall pay the amount 

due within 30 days after receipt of such 

notice. The anniversary date of a lease 

shall not change by reason of any period 

of lease suspension or rental or royalty 

relief resulting therefrom. 

§ 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 

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approaching traffic and shall contain the 

following information which may be 

abbreviated: 

(1) Name of the lease operator; 

(2) The area designation based on 

Official OCS Protraction Diagrams; 

(3) The block number in which the 

facility is located; and 

(4) Vessel, platform, structure, or rig 

name. 

(f)(1) Drilling. (i) When drilling on 

lands valuable or potentially valuable 

for oil and gas or geopressured or 

geothermal resources, drilling 

equipment shall be equipped with 

blowout prevention and control devices 

acceptable to the Director before 

penetrating more than 500 feet unless a 

different depth is specified in advance 

by the Director. 

(ii) In cases where the Director 

determines that there is sufficient 

likelihood of encountering pressurized 

hydrocarbons, the Director may require 

that the lessee comply with all or 

portions of the requirements in part 250, 

subpart D, of this title. 

(iii) Before drilling any hole which 

may penetrate an aquifer, the lessee 

shall follow the procedures included in 

the approved plan for the penetration 

and isolation of the aquifer during the 

drilling operation, during use of the 

hole, and for subsequent abandonment 

of the hole. 

(iv) Cuttings from holes drilled on the 

lease shall be disposed of and 

monitored in accordance with the 

approved plan. 

(v) The use of muds in drilling holes 

on the lease and their subsequent 

disposition shall be according to the 

approved plan. 

(2) All drill holes which are 

susceptible to logging shall be logged, 

and the lessee shall prepare a detailed 

lithologic log of each drill hole. Drill 

holes which are drilled deeper than 500 

feet shall be drilled in a manner which 

permits logging. Copies of logs of cores 

and cuttings and all in-hole surveys 

such as electronic logs, gamma ray logs, 

neutron density logs, and sonic logs 

shall be provided to the Director. 

(3) Drill holes for exploration, testing, 

development, or production shall be 

properly plugged and abandoned to the 

satisfaction of the Director in 

accordance with the approved plan and 

in such a manner as to protect the 

surface and not endanger any operation; 

any freshwater aquifer; or deposit of oil, 

gas, or other mineral substance. 

(g) The use of explosives on the lease 

shall be in accordance with the 

approved plan. 

(h)(1) Any equipment placed on the 

seabed shall be designed to allow its 

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: 

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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. 

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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, including 

practical, 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 

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Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations 64623 

information that BSEE believes is 

necessary to make a decision on 

whether open access or 

nondiscriminatory access was denied. 

(b) If you are a party and fail to 

provide information BSEE requires 

under paragraph (a) of this section, 

BSEE may: 

(1) Assess civil penalties under 30 

CFR part 250, subpart N; 

(2) Dismiss your complaint or 

consider your answer incomplete; or 

(3) Presume the required information 

is adverse to you on the factual issues 

to which the information is relevant. 

(c) If you are not a party to a 

complaint and fail to provide 

information BSEE requires under 

paragraph (a) of this section, BSEE may 

assess civil penalties under 30 CFR part 

250, subpart N. 

§ 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 

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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, 

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Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations 64625 

Draft Proposed Program Outer 

Continental Shelf Oil and Gas Leasing 

Program 2007–2012, dated February 

2006. 

Gulf producing State means each of 

the States of Alabama, Louisiana, 

Mississippi, and Texas. 

Leased tract means any tract that is 

subject to a lease under section 6 or 8 

of the Outer Continental Shelf Lands 

Act for the purpose of drilling for, 

developing, and producing oil or natural 

gas resources. 

Military Mission Line means the 

north-south line at 86°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. 

REVENUE DISTRIBUTION OF QUALIFIED

OCS REVENUES UNDER 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 ........ 30 

Gulf 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 

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coastal political subdivisions in 

amounts that are inversely proportional 

to the respective distances between the 

geographic center of each applicable 

leased tract and the point in each 

coastal political subdivision that is 

closest to the geographic center of each 

applicable leased tract. Except that, an 

applicable leased tract will be excluded 

from this calculation if any portion of 

the tract is located in a geographic area 

that was subject to a leasing moratorium 

on January 1, 2005, unless that tract was 

in production on that date. 

§ 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 (H2S) 

information must accompany the EP? 

550.216 What biological, physical, and 

socioeconomic information must 

accompany the EP? 

550.217 What solid and liquid wastes and 

discharges information and cooling 

water intake information must 

accompany the EP? 

550.218 What air emissions information 

must accompany the EP? 

550.219 What oil and hazardous substance 

spills information must accompany the 

EP? 

550.220 If I propose activities in the Alaska 

OCS Region, what planning information 

must accompany the EP? 

550.221 What environmental monitoring 

information must accompany the EP? 

550.222 What lease stipulations 

information must accompany the EP? 

550.223 What mitigation measures 

information must accompany the EP? 

550.224 What information on support 

vessels, offshore vehicles, and aircraft 

you will use must accompany the EP? 

550.225 What information on the onshore 

support facilities you will use must 

accompany the EP? 

550.226 What Coastal Zone Management 

Act (CZMA) information must 

accompany the EP? 

550.227 What environmental impact 

analysis (EIA) information must 

accompany the EP? 

550.228 What administrative information 

must accompany the EP? 

Review and Decision Process for the EP 

550.231 After receiving the EP, what will 

BOEM do? 

550.232 What actions will BOEM take after 

the EP is deemed submitted? 

550.233 What decisions will BOEM make 

on the EP and within what timeframe? 

550.234 How do I submit a modified EP or 

resubmit a disapproved EP, and when 

will BOEM make a decision? 

550.235 If a State objects to the EP’s coastal 

zone consistency certification, what can 

I do? 

Contents of Development and Production 

Plans (DPP) and Development Operations 

Coordination Documents (DOCD) 

550.241 What must the DPP or DOCD 

include? 

550.242 What information must accompany 

the DPP or DOCD? 

550.243 What general information must 

accompany the DPP or DOCD? 

550.244 What geological and geophysical 

(G&G) information must accompany the 

DPP or DOCD? 

550.245 What hydrogen sulfide (H2S) 

information must accompany the DPP or 

DOCD? 

550.246 What mineral resource 

conservation information must 

accompany the DPP or DOCD? 

550.247 What biological, physical, and 

socioeconomic information must 

accompany the DPP or DOCD? 

550.248 What solid and liquid wastes and 

discharges information and cooling 

water intake information must 

accompany the DPP or DOCD? 

550.249 What air emissions information 

must accompany the DPP or DOCD? 

550.250 What oil and hazardous substance 

spills information must accompany the 

DPP or DOCD? 

550.251 If I propose activities in the Alaska 

OCS Region, what planning information 

must accompany the DPP? 

550.252 What environmental monitoring 

information must accompany the DPP or 

DOCD? 

550.253 What lease stipulations 

information must accompany the DPP or 

DOCD? 

550.254 What mitigation measures 

information must accompany the DPP or 

DOCD? 

550.255 What decommissioning 

information must accompany the DPP or 

DOCD? 

550.256 What related facilities and 

operations information must accompany 

the DPP or DOCD? 

550.257 What information on the support 

vessels, offshore vehicles, and aircraft 

you will use must accompany the DPP or 

DOCD? 

550.258 What information on the onshore 

support facilities you will use must 

accompany the DPP or DOCD? 

550.259 What sulphur operations 

information must accompany the DPP or 

DOCD? 

550.260 What Coastal Zone Management 

Act (CZMA) information must 

accompany the DPP or DOCD? 

550.261 What environmental impact 

analysis (EIA) information must 

accompany the DPP or DOCD? 

550.262 What administrative information 

must accompany the DPP or DOCD? 

Review and Decision Process for the DPP or 

DOCD 

550.266 After receiving the DPP or DOCD, 

what will BOEM do? 

550.267 What actions will BOEM take after 

the DPP or DOCD is deemed submitted? 

550.268 How does BOEM respond to 

recommendations? 

550.269 How will BOEM evaluate the 

environmental impacts of the DPP or 

DOCD? 

550.270 What decisions will BOEM make 

on the DPP or DOCD and within what 

timeframe? 

550.271 For what reasons will BOEM 

disapprove the DPP or DOCD? 

550.272 If a State objects to the DPP’s or 

DOCD’s coastal zone consistency 

certification, what can I do? 

550.273 How do I submit a modified DPP 

or DOCD or resubmit a disapproved DPP 

or DOCD? 

Post-Approval Requirements for the EP, 

DPP, and DOCD 

550.280 How must I conduct activities 

under the approved EP, DPP, or DOCD? 

550.281 What must I do to conduct 

activities under the approved EP, DPP, or 

DOCD? 

550.282 Do I have to conduct post-approval 

monitoring? 

550.283 When must I revise or supplement 

the approved EP, DPP, or DOCD? 

550.284 How will BOEM require revisions 

to the approved EP, DPP, or DOCD? 

550.285 How do I submit revised and 

supplemental EPs, DPPs, and DOCDs? 

Conservation Information Documents (CID) 

550.296 When and how must I submit a CID 

or a revision to a CID? 

550.297 What information must a CID 

contain? 

550.298 How long will BOEM take to 

evaluate and make a decision on the 

CID? 

550.299 What operations require approval 

of the CID? 

Subpart C—Pollution Prevention and 

Control 

550.300 [Reserved] 

550.301 [Reserved] 

550.302 Definitions concerning air quality. 

550.303 Facilities described in a new or 

revised Exploration Plan or Development 

and Production Plan. 

550.304 Existing facilities. 

Subpart D—[Reserved] 

Subpart E—[Reserved] 

Subpart F—[Reserved] 

Subpart G—[Reserved] 

Subpart H—[Reserved] 

Subpart I—[Reserved] 

Subpart J—Pipelines and Pipeline Rights of 

Way 

550.1011 Bond requirements for pipeline 

right-of-way holders. 

Subpart K—Oil and Gas Production 

Requirements 

Well Tests and Surveys 

550.1153 When must I conduct a static 

bottomhole pressure survey? 

Classifying Reservoirs 

550.1154 How do I determine if my 

reservoir is sensitive? 

550.1155 What information must I submit 

for sensitive reservoirs? 

Other Requirements 

550.1165 What must I do for enhanced 

recovery operations? 

550.1166 What additional reporting is 

required for developments in the Alaska 

OCS Region? 

550.1167 What information must I submit 

with forms and for approvals? 

Subpart L—[Reserved] 

Subpart M—[Reserved] 

Subpart N—Outer Continental Shelf Civil 

Penalties 

Outer Continental Shelf Lands Act Civil 

Penalties 

550.1400 How does BOEM begin the civil 

penalty process? 

550.1401 Index table. 

550.1402 Definitions. 

550.1403 What is the maximum civil 

penalty? 

550.1404 Which violations will BOEM 

review for potential civil penalties? 

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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—WHERE TO FIND INFORMATION FOR CONDUCTING OPERATIONS

For information about Refer to 

(1) Applications for permit to drill ............................................................. 30 CFR 250, subpart D. 

(2) Development and Production Plans (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.

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§ 550.103 Where can I find more 

information about the requirements in this 

part? 

BOEM may issue Notices to Lessees 

and Operators (NTLs) that clarify, 

supplement, or provide more detail 

about certain requirements. NTLs may 

also outline what you must provide as 

required information in your various 

submissions to BOEM. 

§ 550.104 How may I appeal a decision 

made under BOEM regulations? 

To appeal orders or decisions issued 

under BOEM regulations in 30 CFR 

parts 550 to 582, follow the procedures 

in 30 CFR part 590. 

§ 550.105 Definitions. 

Terms used in this part will have the 

meanings given in the Act and as 

defined in this section: 

Act means the OCS Lands Act, as 

amended (43 U.S.C. 1331 et seq.). 

Affected State means with respect to 

any program, plan, lease sale, or other 

activity proposed, conducted, or 

approved under the provisions of the 

Act, any State: 

(1) The laws of which are declared, 

under section 4(a)(2) of the Act, to be 

the law of the United States for the 

portion of the OCS on which such 

activity is, or is proposed to be, 

conducted; 

(2) Which is, or is proposed to be, 

directly connected by transportation 

facilities to any artificial island or 

installation or other device permanently 

or temporarily attached to the seabed; 

(3) Which is receiving, or according to 

the proposed activity, will receive oil 

for processing, refining, or 

transshipment that was extracted from 

the OCS and transported directly to 

such State by means of vessels or by a 

combination of means including vessels; 

(4) Which is designated by the 

Secretary as a State in which there is a 

substantial probability of significant 

impact on or damage to the coastal, 

marine, or human environment, or a 

State in which there will be significant 

changes in the social, governmental, or 

economic infrastructure, resulting from 

the exploration, development, and 

production of oil and gas anywhere on 

the OCS; or 

(5) In which the Secretary finds that 

because of such activity there is, or will 

be, a significant risk of serious damage, 

due to factors such as prevailing winds 

and currents to the marine or coastal 

environment in the event of any oil 

spill, blowout, or release of oil or gas 

from vessels, pipelines, or other 

transshipment facilities. 

Air pollutant means any airborne 

agent or combination of agents for 

which the Environmental Protection 

Agency (EPA) has established, under 

section 109 of the Clean Air Act, 

national primary or secondary ambient 

air quality standards. 

Analyzed geological information 

means data collected under a permit or 

a lease that have been analyzed. 

Analysis may include, but is not limited 

to, identification of lithologic and fossil 

content, core analysis, laboratory 

analyses of physical and chemical 

properties, well logs or charts, results 

from formation fluid tests, and 

descriptions of hydrocarbon 

occurrences or hazardous conditions. 

Ancillary activities mean those 

activities on your lease or unit that you: 

(1) Conduct to obtain data and 

information to ensure proper 

exploration or development of your 

lease or unit; and 

(2) Can conduct without BOEM 

approval of an application or permit. 

Archaeological interest means capable 

of providing scientific or humanistic 

understanding of past human behavior, 

cultural adaptation, and related topics 

through the application of scientific or 

scholarly techniques, such as controlled 

observation, contextual measurement, 

controlled collection, analysis, 

interpretation, and explanation. 

Archaeological resource means any 

material remains of human life or 

activities that are at least 50 years of age 

and that are of archaeological interest. 

Attainment area means, for any air 

pollutant, an area that is shown by 

monitored data or that is calculated by 

air quality modeling (or other methods 

determined by the Administrator of EPA 

to be reliable) not to exceed any primary 

or secondary ambient air quality 

standards established by EPA. 

Best available and safest technology 

(BAST) means the best available and 

safest technologies that the Director 

determines to be economically feasible 

wherever failure of equipment would 

have a significant effect on safety, 

health, or the environment. 

Best available control technology 

(BACT) means an emission limitation 

based on the maximum degree of 

reduction for each air pollutant subject 

to regulation, taking into account 

energy, environmental and economic 

impacts, and other costs. The Regional 

Director will verify the BACT on a 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 

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or imply the presence of oil, gas, or 

sulphur in commercial quantities. 

Director means the Director of BOEM 

of the U.S. Department of the Interior, 

or an official authorized to act on the 

Director’s behalf. 

District Manager means the BSEE 

officer with authority and responsibility 

for operations or other designated 

program functions for a district within 

a BSEE Region. 

Easement means an authorization for 

a nonpossessory, nonexclusive interest 

in a portion of the OCS, whether leased 

or unleased, which specifies the rights 

of the holder to use the area embraced 

in the easement in a manner consistent 

with the terms and conditions of the 

granting authority. 

Eastern Gulf of Mexico means all OCS 

areas of the Gulf of Mexico the BOEM 

Director decides are adjacent to the 

State of Florida. The Eastern Gulf of 

Mexico is not the same as the Eastern 

Planning Area, an area established for 

OCS lease sales. 

Emission offsets mean emission 

reductions obtained from facilities, 

either onshore or offshore, other than 

the facility or facilities covered by the 

proposed Exploration Plan (EP) or 

Development and Production Plan 

(DPP). 

Enhanced recovery operations mean 

pressure maintenance operations, 

secondary and tertiary recovery, cycling, 

and similar recovery operations that 

alter the natural forces in a reservoir to 

increase the ultimate recovery of oil or 

gas. 

Existing facility, as used in § 550.303, 

means an OCS facility described in an 

Exploration Plan or a Development and 

Production Plan approved before June 2, 

1980. 

Exploration means the commercial 

search for oil, gas, or sulphur. Activities 

classified as exploration include but are 

not limited to: 

(1) Geophysical and geological (G&G) 

surveys using magnetic, gravity, seismic 

reflection, seismic refraction, gas 

sniffers, coring, or other systems to 

detect or imply the presence of oil, gas, 

or sulphur; and 

(2) Any drilling conducted for the 

purpose of searching for commercial 

quantities of oil, gas, and sulphur, 

including the drilling of any additional 

well needed to delineate any reservoir 

to enable the lessee to decide whether 

to proceed with development and 

production. 

Facility, as used in § 550.303, means 

all installations or devices permanently 

or temporarily attached to the seabed. 

They include mobile offshore drilling 

units (MODUs), even while operating in 

the ‘‘tender assist’’ mode (i.e., with 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. 

H2S absent means: 

(1) Drilling, logging, coring, testing, or 

producing operations have confirmed 

the absence of H2S in concentrations 

that could potentially result in 

atmospheric concentrations of 20 ppm 

or more of H2S; or 

(2) Drilling in the surrounding areas 

and correlation of geological and 

seismic data with equivalent 

stratigraphic units have confirmed an 

absence of H2S throughout the area to be 

drilled. 

H2S present means drilling, logging, 

coring, testing, or producing operations 

have confirmed the presence of H2S in 

concentrations and volumes that could 

potentially result in atmospheric 

concentrations of 20 ppm or more of 

H2S. 

H2S unknown means the designation 

of a zone or geologic formation where 

neither the presence nor absence of H2S 

has been confirmed. 

Human environment means the 

physical, social, and economic 

components, conditions, and factors 

that interactively determine the state, 

condition, and quality of living 

conditions, employment, and health of 

those affected, directly or indirectly, by 

activities occurring on the OCS. 

Interpreted geological information 

means geological knowledge, often in 

the form of schematic cross sections, 3- 

dimensional representations, and maps, 

developed by determining the geological 

significance of data and analyzed 

geological information. 

Interpreted geophysical information 

means geophysical knowledge, often in 

the form of schematic cross sections, 3- 

dimensional representations, and maps, 

developed by determining the geological 

significance of geophysical data and 

analyzed geophysical information. 

Lease means an agreement that is 

issued under section 8 or maintained 

under section 6 of the Act and that 

authorizes exploration for, and 

development and production of, 

minerals. The term also means the area 

covered by that authorization, 

whichever the context requires. 

Lease term pipelines mean those 

pipelines owned and operated by a 

lessee or operator that are completely 

contained within the boundaries of a 

single lease, unit, or contiguous (not 

cornering) leases of that lessee or 

operator. 

Lessee means a person who has 

entered into a lease with the United 

States to explore for, develop, and 

produce the leased minerals. The term 

lessee also includes the BOEMapproved assignee of the lease, and the 

owner or the BOEM-approved assignee 

of operating rights for the lease. 

Major Federal action means any 

action or proposal by the Secretary that 

is subject to the provisions of section 

102(2)(C) of the National Environmental 

Policy Act of 1969, 42 U.S.C. (2)(C) (i.e., 

an action that will have a significant 

impact on the quality of the human 

environment requiring preparation of an 

environmental impact statement under 

section 102(2)(C) of the National 

Environmental Policy Act). 

Marine environment means the 

physical, atmospheric, and biological 

components, conditions, and factors 

that interactively determine the 

productivity, state, condition, and 

quality of the marine ecosystem. These 

include the waters of the high seas, the 

contiguous zone, transitional and 

intertidal areas, salt marshes, and 

wetlands within the coastal zone and on 

the OCS. 

Material remains means physical 

evidence of human habitation, 

occupation, use, or activity, including 

the site, location, or context in which 

such evidence is situated. 

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Maximum efficient rate (MER) means 

the maximum sustainable daily oil or 

gas withdrawal rate from a reservoir that 

will permit economic development and 

depletion of that reservoir without 

detriment to ultimate recovery. 

Maximum production rate (MPR) 

means the approved maximum daily 

rate at which oil or gas may be produced 

from a specified oil-well or gas-well 

completion. 

Minerals include oil, gas, sulphur, 

geopressured-geothermal and associated 

resources, and all other minerals that 

are authorized by an Act of Congress to 

be produced. 

Natural resources include, without 

limiting the generality thereof, oil, gas, 

and all other minerals, and fish, shrimp, 

oysters, clams, crabs, lobsters, sponges, 

kelp, and other marine animal and plant 

life but does not include water power or 

the use of water for the production of 

power. 

Nonattainment area means, for any 

air pollutant, an area that is shown by 

monitored data or that is calculated by 

air quality modeling (or other methods 

determined by the Administrator of EPA 

to be reliable) to exceed any primary or 

secondary ambient air quality standard 

established by EPA. 

Nonsensitive reservoir means a 

reservoir in which ultimate recovery is 

not decreased by high reservoir 

production rates. 

Oil reservoir means a reservoir that 

contains hydrocarbons predominantly 

in a liquid (single-phase) state. 

Oil reservoir with an associated gas 

cap means a reservoir that contains 

hydrocarbons in both a liquid and 

gaseous (two-phase) state. 

Oil-well completion means a well 

completed in an oil reservoir or in the 

oil accumulation of an oil reservoir with 

an associated gas cap. 

Operating rights mean any interest 

held in a lease with the right to explore 

for, develop, and produce leased 

substances. 

Operator means the person the 

lessee(s) designates as having control or 

management of operations on the leased 

area or a portion thereof. An operator 

may be a lessee, the BOEM-approved or 

BSEE-approved designated agent of the 

lessee(s), or the holder of operating 

rights under a BOEM-approved 

operating rights assignment. 

Outer Continental Shelf (OCS) means 

all submerged lands lying seaward and 

outside of the area of lands beneath 

navigable waters as defined in section 2 

of the Submerged Lands Act (43 U.S.C. 

1301) whose subsoil and seabed 

appertain to the United States and are 

subject to its jurisdiction and control. 

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 to 

annual rental includes the areal extent of anchor chains, pipeline risers, and other equipment associated with the platform, artificial island, installation or device. 

(2) Your right-of-use and easement 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 subject 

to annual rental includes the areal extent of anchor chains, pipeline risers, and other equipment associated with the platform, artificial island, or installation or device. 

(h) You may make the rental 

payments required by paragraph (g)(1) 

and (g)(2) of this section on an annual 

basis, for a 5-year period, or for 

multiples of 5 years. You must make the 

first payment electronically through 

Pay.gov and you must include a copy of 

the Pay.gov confirmation receipt page 

with your right-of-use and easement 

application. You must make all 

subsequent payments before the 

respective time periods begin. 

(i) Late payments. An interest charge 

will be assessed on unpaid and 

underpaid amounts from the date the 

amounts are due, in accordance with the 

provisions found in 30 CFR 1218.54. If 

you fail to make a payment that is late 

after written notice from BOEM, BOEM 

may initiate cancellation of the right-ofuse grant and easement. 

§ 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 that 

portion of the OCS on which your rightof-use and easement is situated must 

continue to recognize the right-of-use 

and easement for the purpose that the 

grant specifies. 

§ 550.163 If I have a State lease, will BOEM 

grant me a right-of-use and easement? 

(a) BOEM may grant a lessee of a State 

lease located adjacent to or accessible 

from the OCS a right-of-use and 

easement on the OCS. 

(b) BOEM will only grant a right-ofuse and easement under this paragraph 

to enable a State lessee to conduct and 

maintain a device that is permanently or 

temporarily attached to the seabed (i.e., 

a platform, artificial island, or 

installation). The lessee must use the 

device to explore for, develop, and 

produce oil and gas from the adjacent or 

accessible State lease and for other 

operations related to these activities. 

§ 550.164 If I have a State lease, what 

conditions apply for a right-of-use and 

easement? 

(a) A right-of-use and easement 

granted under the heading of ‘‘Right-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 site 

clearance from the seafloor of the rightof-use and easement. 

Primary Lease Requirements, Lease 

Term Extensions, and Lease 

Cancellations 

§ 550.181 When may the Secretary cancel 

my lease and when am I compensated for 

cancellation? 

If the Secretary cancels your lease 

under this part or under 30 CFR part 

556, you are entitled to compensation 

under § 550.184. Section 550.185 states 

conditions under which you will 

receive no compensation. The Secretary 

may cancel a lease after notice and 

opportunity for a hearing when: 

(a) Continued activity on the lease 

would probably cause harm or damage 

to life (including fish and other aquatic 

life), property, any mineral deposits (in 

areas leased or not leased), or the 

marine, coastal, or human environment; 

(b) The threat of harm or damage will 

not disappear or decrease to an 

acceptable extent within a reasonable 

period of time; 

(c) The advantages of cancellation 

outweigh the advantages of continuing 

the lease in force; and 

(d) A suspension has been in effect for 

at least 5 years or you request 

termination of the suspension and lease 

cancellation. 

§ 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. 

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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 with 

safety or environmental protection requirements, 

Geophysical data, Geological 

data, Interpreted G&G information, Processed geological information, Analyzed geological information, 

60 days after BOEM receives the 

data or information, if the Regional Supervisor deems it necessary, 

BOEM will release the data and 

information earlier than 60 days 

if the Regional Supervisor determines it is needed by affected States to make decisions 

under subpart B. The Regional 

Supervisor will reconsider earlier release if you satisfy him/ 

her that it would unduly damage your competitive position. 

(3) Your lease is no longer in effect, Geophysical data, Geological 

data, Processed G&G information Interpreted G&G information, Analyzed geological information, 

When your lease terminates, This release time applies only if 

the provisions in this table governing high-resolution systems 

and the provisions in § 552.7 do 

not apply. The release time applies to the geophysical data 

and information only if acquired 

postlease for a lessee’s exclusive use. 

(4) Your lease is still in effect, Geophysical data, Processed 

geophysical information, Interpreted G&G information, 

10 years after you submit the 

data and information, 

This release time applies only if 

the provisions in this table governing high-resolution systems 

and the provisions in § 552.7 do 

not apply. This release time applies to the geophysical data 

and information only if acquired 

postlease for a lessee’s exclusive use. 

(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 if 

the provisions in this table governing high-resolution systems 

and the provisions in § 552.7 do 

not apply. If the primary term 

specified in the lease is extended under the heading of 

‘‘Suspensions’’ in this subpart, 

the extension applies to this 

provision. 

(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 production 

or 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 the 

permit; 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 

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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 on 

OCS 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, ROV 

Survey 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, and 

coastal 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 the 

OCS. 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 (H2S) releases. 

§ 550.208 If I conduct ancillary activities, 

what notices must I provide? 

At least 30 calendar days before you 

conduct any G&G exploration or 

development G&G activity (see 

§ 550.207(a)), you must notify the 

Regional Supervisor in writing. 

(a) When you prepare the notice, you 

must: 

(1) Sign and date the notice; 

(2) Provide the names of the vessel, its 

operator, and the person(s) in charge; 

the specific type(s) of operations you 

will conduct; and the instrumentation/ 

techniques and vessel navigation system 

you will use; 

(3) Provide expected start and 

completion dates and the location of the 

activity; and 

(4) Describe the potential adverse 

environmental effects of the proposed 

activity and any mitigation to eliminate 

or minimize these effects on the marine, 

coastal, and human environment. 

(b) The Regional Supervisor may 

require you to: 

(1) Give written notice to BOEM at 

least 15 calendar days before you 

conduct any other ancillary activity (see 

§ 550.207(b) and (c)) in addition to those 

listed in § 550.207(a); and 

(2) Notify other users of the OCS 

before you conduct any ancillary 

activity. 

§ 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 the 

top of each prospective hydrocarbonbearing reservoir showing the locations 

of proposed wells. 

(c) Two-dimensional (2–D) or threedimensional (3–D) seismic lines. Copies 

of migrated and annotated 2–D or 3–D 

seismic lines (with depth scale) 

intersecting at or near your proposed 

well locations. You are not required to 

conduct both 2–D and 3–D seismic 

surveys if you choose to conduct only 

one type of survey. If you have 

conducted both types of surveys, the 

Regional Supervisor may instruct you to 

submit the results of both surveys. You 

must interpret and display this 

information. Because of its volume, 

provide this information as an enclosure 

to only one proprietary copy of your EP. 

(d) Geological cross-sections. 

Interpreted geological cross-sections 

showing the location and depth of each 

proposed well. 

(e) Shallow hazards report. A shallow 

hazards report based on information 

obtained from a high-resolution 

geophysical survey, or a reference to 

such report if you have already 

submitted it to the Regional Supervisor. 

(f) Shallow hazards assessment. For 

each proposed well, an assessment of 

any seafloor and subsurface geological 

and manmade features and conditions 

that may adversely affect your proposed 

drilling operations. 

(g) High-resolution seismic lines. A 

copy of the high-resolution survey line 

closest to each of your proposed well 

locations. Because of its volume, 

provide this information as an enclosure 

to only one proprietary copy of your EP. 

You are not required to provide this 

information if the surface location of 

your proposed well has been approved 

in a previously submitted EP, DPP, or 

DOCD. 

(h) Stratigraphic column. A 

generalized biostratigraphic/ 

lithostratigraphic column from the 

surface to the total depth of the 

prospect. 

(i) Time-versus-depth chart. A seismic 

travel time-versus-depth chart based on 

the appropriate velocity analysis in the 

area of interpretation and specifying the 

geodetic datum. 

(j) Geochemical information. A copy 

of any geochemical reports you used or 

generated. 

(k) Future G&G activities. A brief 

description of the types of G&G 

explorations and development G&G 

activities you may conduct for lease or 

unit purposes after your EP is approved. 

§ 550.215 What hydrogen sulfide (H2S) 

information must accompany the EP? 

The following H2S information, as 

applicable, must accompany your EP: 

(a) Concentration. The estimated 

concentration of any H2S you might 

encounter while you conduct your 

proposed exploration activities. 

(b) Classification. Under 30 CFR 

250.490(c), a request that the BSEE 

Regional Supervisor classify the area of 

your proposed exploration activities as 

either H2S absent, H2S present, or H2S 

unknown. Provide sufficient 

information to justify your request. 

(c) H2S Contingency Plan. If you ask 

the Regional Supervisor to classify the 

area of your proposed exploration 

activities as either H2S present or H2S 

unknown, an H2S Contingency Plan 

prepared under 30 CFR 250.490(f), or a 

reference to an approved or submitted 

H2S Contingency Plan that covers the 

proposed exploration activities. 

(d) Modeling report. If you modeled a 

potential H2S release when developing 

your EP, modeling report or the 

modeling results, or a reference to such 

report or results if you have already 

submitted it to the Regional Supervisor. 

(1) The analysis in the modeling 

report must be specific to the particular 

site of your proposed exploration 

activities, and must consider any nearby 

human-occupied OCS facilities, 

shipping lanes, fishery areas, and other 

points where humans may be subject to 

potential exposure from an H2S release 

from your proposed exploration 

activities. 

(2) If any H2S emissions are projected 

to affect an onshore location in 

concentrations greater than 10 parts per 

million, the modeling analysis must be 

consistent with the Environmental 

Protection Agency’s (EPA) risk 

management plan methodologies 

outlined in 40 CFR part 68. 

§ 550.216 What biological, physical, and 

socioeconomic information must 

accompany the EP? 

If you obtain the following 

information in developing your EP, or if 

the Regional Supervisor requires you to 

obtain it, you must include a report, or 

the information obtained, or a reference 

to such a report or information if you 

have already submitted it to the 

Regional Supervisor, as accompanying 

information: 

(a) Biological environment reports. 

Site-specific information on 

chemosynthetic communities, federally 

listed threatened or endangered species, 

marine mammals protected under the 

Marine Mammal Protection Act 

(MMPA), sensitive underwater features, 

marine sanctuaries, critical habitat 

designated under the Endangered 

Species Act (ESA), or other areas of 

biological concern. 

(b) Physical environment reports. Sitespecific meteorological, physical 

oceanographic, geotechnical reports, or 

archaeological reports (if required under 

§ 550.194). 

(c) Socioeconomic study reports. 

Socioeconomic information regarding 

your proposed exploration activities. 

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§ 550.217 What solid and liquid wastes 

and discharges information and cooling 

water intake information must accompany 

the EP? 

The following solid and liquid wastes 

and discharges information and cooling 

water intake information must 

accompany your EP: 

(a) Projected wastes. A table providing 

the name, brief description, projected 

quantity, and composition of solid and 

liquid wastes (such as spent drilling 

fluids, drill cuttings, trash, sanitary and 

domestic wastes, and chemical product 

wastes) likely to be generated by your 

proposed exploration activities. 

Describe: 

(1) The methods you used for 

determining this information; and 

(2) Your plans for treating, storing, 

and downhole disposal of these wastes 

at your drilling location(s). 

(b) Projected ocean discharges. If any 

of your solid and liquid wastes will be 

discharged overboard, or are planned 

discharges from manmade islands: 

(1) A table showing the name, 

projected amount, and rate of discharge 

for each waste type; and 

(2) A description of the discharge 

method (such as shunting through a 

downpipe, etc.) you will use. 

(c) National Pollutant Discharge 

Elimination System (NPDES) permit. (1) 

A discussion of how you will comply 

with the provisions of the applicable 

general NPDES permit that covers your 

proposed exploration activities; or 

(2) A copy of your application for an 

individual NPDES permit. Briefly 

describe the major discharges and 

methods you will use for compliance. 

(d) Modeling report. The modeling 

report or the modeling results (if you 

modeled the discharges of your 

projected solid or liquid wastes when 

developing your EP), or a reference to 

such report or results if you have 

already submitted it to the Regional 

Supervisor. 

(e) Projected cooling water intake. A 

table for each cooling water intake 

structure likely to be used by your 

proposed exploration activities that 

includes a brief description of the 

cooling water intake structure, daily 

water intake rate, water intake through 

screen velocity, percentage of water 

intake used for cooling water, mitigation 

measures for reducing impingement and 

entrainment of aquatic organisms, and 

biofouling prevention measures. 

§ 550.218 What air emissions information 

must accompany the EP? 

The following air emissions 

information, as applicable, must 

accompany your EP: 

(a) Projected emissions. Tables 

showing the projected emissions of 

sulphur dioxide (SO2), particulate 

matter in the form of PM10 and PM2.5

when applicable, nitrogen oxides (NOX), 

carbon monoxide (CO), and volatile 

organic compounds (VOC) that will be 

generated by your proposed exploration 

activities. 

(1) For each source on or associated 

with the drilling unit (including well 

test flaring and well protection structure 

installation), you must list: 

(i) The projected peak hourly 

emissions; 

(ii) The total annual emissions in tons 

per year; 

(iii) Emissions over the duration of 

the proposed exploration activities; 

(iv) The frequency and duration of 

emissions; and 

(v) The total of all emissions listed in 

paragraphs (a)(1)(i) through (iv) of this 

section. 

(2) You must provide the basis for all 

calculations, including engine size and 

rating, and applicable operational 

information. 

(3) You must base the projected 

emissions on the maximum rated 

capacity of the equipment on the 

proposed drilling unit under its 

physical and operational design. 

(4) If the specific drilling unit has not 

yet been determined, you must use the 

maximum emission estimates for the 

type of drilling unit you will use. 

(b) Emission reduction measures. A 

description of any proposed emission 

reduction measures, including the 

affected source(s), the emission 

reduction control technologies or 

procedures, the quantity of reductions 

to be achieved, and any monitoring 

system you propose to use to measure 

emissions. 

(c) Processes, equipment, fuels, and 

combustibles. A description of 

processes, processing equipment, 

combustion equipment, fuels, and 

storage units. You must include the 

characteristics and the frequency, 

duration, and maximum burn rate of 

any well test fluids to be burned. 

(d) Distance to shore. Identification of 

the distance of your drilling unit from 

the mean high water mark (mean higher 

high water mark on the Pacific coast) of 

the adjacent State. 

(e) Non-exempt drilling units. A 

description of how you will comply 

with § 550.303 when the projected 

emissions of SO2, PM, NOX, CO, or 

VOC, that will be generated by your 

proposed exploration activities, are 

greater than the respective emission 

exemption amounts ‘‘E’’ calculated 

using the formulas in § 550.303(d). 

When BOEM requires air quality 

modeling, you must use the guidelines 

in Appendix W of 40 CFR part 51 with 

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 calendar 

days after receiving your deemedsubmitted EP to submit comments. The 

Regional Supervisor will not consider 

comments received after the deadline. 

(2) The CZMA agency of each affected 

State. The CZMA consistency review 

period under section 307(c)(3)(B)(ii) of 

the CZMA (16 U.S.C. 1456(c)(3)(B)(ii)) 

and 15 CFR 930.78 begins when the 

State’s CZMA agency receives a copy of 

your deemed-submitted EP, consistency 

certification, and required necessary 

data and information (see 15 CFR 

930.77(a)(1)). 

(b) BOEM compliance review. The 

Regional Supervisor will review the 

exploration activities described in your 

proposed EP to ensure that they 

conform to the performance standards 

in § 550.202. 

(c) BOEM environmental impact 

evaluation. The Regional Supervisor 

will evaluate the environmental impacts 

of the activities described in your 

proposed EP and prepare environmental 

documentation under the National 

Environmental Policy Act (NEPA) (42 

U.S.C. 4321 et seq.) and the 

implementing regulations (40 CFR parts 

1500 through 1508). 

(d) Amendments. During the review 

of your proposed EP, the Regional 

Supervisor may require you, or you may 

elect, to change your EP. If you elect to 

amend your EP, the Regional Supervisor 

may determine that your EP, as 

amended, is subject to the requirements 

of § 550.231. 

§ 550.233 What decisions will BOEM make 

on the EP and within what timeframe? 

(a) Timeframe. The Regional 

Supervisor will take one of the actions 

shown in the table in paragraph (b) of 

this section within 30 calendar days 

after the Regional Supervisor deems 

your EP submitted under § 550.231, or 

receives the last amendment to your 

proposed EP, whichever occurs later. 

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(b) BOEM decision. By the deadline in 

paragraph (a) of this section, the 

Regional Supervisor will take one of the 

following actions: 

The regional 

supervisor will . . . If . . . And then . . . 

(1) Approve your EP, It complies with all applicable requirements, The Regional Supervisor will notify you in writing of the 

decision and may require you to meet certain conditions, including those to provide monitoring information. 

(2) Require you to modify 

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 serious 

harm or damage to life (including fish or other aquatic life); property; any mineral (in areas leased or not 

leased); the National security or defense; or the marine, coastal, or human environment; and you cannot 

modify your proposed activities to avoid such condition(s), 

(i) The Regional Supervisor will notify you in writing of 

the decision and describe the reason(s) for disapproving your EP. 

(ii) BOEM may cancel your lease and compensate you 

under 43 U.S.C. 1334(a)(2)(C) and the implementing 

regulations in §§ 550.182, 550.184, and 550.185 and 

30 CFR 556.77. 

§ 550.234 How do I submit a modified EP 

or resubmit a disapproved EP, and when 

will BOEM make a decision? 

(a) Modified EP. If the Regional 

Supervisor requires you to modify your 

proposed EP under § 550.233(b)(2), you 

must submit the modification(s) to the 

Regional Supervisor in the same manner 

as for a new EP. You need submit only 

information related to the proposed 

modification(s). 

(b) Resubmitted EP. If the Regional 

Supervisor disapproves your EP under 

§ 550.233(b)(3), you may resubmit the 

disapproved EP if there is a change in 

the conditions that were the basis of its 

disapproval. 

(c) BOEM review and timeframe. The 

Regional Supervisor will use the 

performance standards in § 550.202 to 

either approve, require you to further 

modify, or disapprove your modified or 

resubmitted EP. The Regional 

Supervisor will make a decision within 

30 calendar days after the Regional 

Supervisor deems your modified or 

resubmitted EP to be submitted, or 

receives the last amendment to your 

modified or resubmitted EP, whichever 

occurs later. 

§ 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 (H2S) 

information must accompany the DPP or 

DOCD? 

The following H2S information, as 

applicable, must accompany your DPP 

or DOCD: 

(a) Concentration. The estimated 

concentration of any H2S you might 

encounter or handle while you conduct 

your proposed development and 

production activities. 

(b) Classification. Under 30 CFR 

250.490(c), a request that the Regional 

Supervisor classify the area of your 

proposed development and production 

activities as either H2S absent, H2S 

present, or H2S unknown. Provide 

sufficient information to justify your 

request. 

(c) H 2S Contingency Plan. If you 

request that the Regional Supervisor 

classify the area of your proposed 

development and production activities 

as either H2S present or H2S unknown, 

an H2S Contingency Plan prepared 

under 30 CFR 250.490(f), or a reference 

to an approved or submitted H2S 

Contingency Plan that covers the 

proposed development and production 

activities. 

(d) Modeling report. (1) If you have 

determined or estimated that the 

concentration of any H2S you may 

encounter or handle while you conduct 

your development and production 

activities will be greater than 500 parts 

per million (ppm), you must: 

(i) Model a potential worst case H2S 

release from the facilities you will use 

to conduct your proposed development 

and production activities; and 

(ii) Include a modeling report or 

modeling results, or a reference to such 

report or results if you have already 

submitted it to the Regional Supervisor. 

(2) The analysis in the modeling 

report must be specific to the particular 

site of your development and 

production activities, and must consider 

any nearby human-occupied OCS 

facilities, shipping lanes, fishery areas, 

and other points where humans may be 

subject to potential exposure from an 

H2S release from your proposed 

activities. 

(3) If any H2S emissions are projected 

to affect an onshore location in 

concentrations greater than 10 ppm, the 

modeling analysis must be consistent 

with the EPA’s risk management plan 

methodologies outlined in 40 CFR part 

68. 

§ 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 (SO2), particulate 

matter in the form of PM10 and PM2.5

when applicable, nitrogen oxides (NOX), 

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carbon monoxide (CO), and volatile 

organic compounds (VOC) that will be 

generated by your proposed 

development and production activities. 

(1) For each source on or associated 

with the facility you will use to conduct 

your proposed development and 

production activities, you must list: 

(i) The projected peak hourly 

emissions; 

(ii) The total annual emissions in tons 

per year; 

(iii) Emissions over the duration of 

the proposed development and 

production activities; 

(iv) The frequency and duration of 

emissions; and 

(v) The total of all emissions listed in 

paragraph (a)(1)(i) through (iv) of this 

section. 

(2) If your proposed production and 

development activities would result in 

an increase in the emissions of an air 

pollutant from your facility to an 

amount greater than the amount 

specified in your previously approved 

DPP or DOCD, you must show the 

revised emission rates for each source as 

well as the incremental change for each 

source. 

(3) You must provide the basis for all 

calculations, including engine size and 

rating, and applicable operational 

information. 

(4) You must base the projected 

emissions on the maximum rated 

capacity of the equipment and the 

maximum throughput of the facility you 

will use to conduct your proposed 

development and production activities 

under its physical and operational 

design. 

(5) If the specific drilling unit has not 

yet been determined, you must use the 

maximum emission estimates for the 

type of drilling unit you will use. 

(b) Emission reduction measures. A 

description of any proposed emission 

reduction measures, including the 

affected source(s), the emission 

reduction control technologies or 

procedures, the quantity of reductions 

to be achieved, and any monitoring 

system you propose to use to measure 

emissions. 

(c) Processes, equipment, fuels, and 

combustibles. A description of 

processes, processing equipment, 

combustion equipment, fuels, and 

storage units. You must include the 

frequency, duration, and maximum 

burn rate of any flaring activity. 

(d) Distance to shore. Identification of 

the distance of the site of your proposed 

development and production activities 

from the mean high water mark (mean 

higher high water mark on the Pacific 

coast) of the adjacent State. 

(e) Non-exempt facilities. A 

description of how you will comply 

with § 550.303 when the projected 

emissions of SO2, PM, NOX, CO, or VOC 

that will be generated by your proposed 

development and production activities 

are greater than the respective emission 

exemption amounts ‘‘E’’ calculated 

using the formulas in § 550.303(d). 

When BOEM requires air quality 

modeling, you must use the guidelines 

in Appendix W of 40 CFR part 51 with 

a model approved by the Director. 

Submit the best available meteorological 

information and data consistent with 

the model(s) used. 

(f) Modeling report. A modeling report 

or the modeling results (if § 550.303 

requires you to use an approved air 

quality model to model projected air 

emissions in developing your DPP or 

DOCD), or a reference to such report or 

results if you have already submitted it 

to the Regional Supervisor. 

§ 550.250 What oil and hazardous 

substance spills information must 

accompany the DPP or DOCD? 

The following information regarding 

potential spills of oil (see definition 

under 30 CFR 254.6) and hazardous 

substances (see definition under 40 CFR 

part 116), as applicable, must 

accompany your DPP or DOCD: 

(a) Oil spill response planning. The 

material required under paragraph (a)(1) 

or (a)(2) of this section: 

(1) An Oil Spill Response Plan (OSRP) 

for the facilities you will use to conduct 

your proposed development and 

production activities prepared 

according to the requirements of 30 CFR 

part 254, subpart B; or 

(2) Reference to your approved 

regional OSRP (see 30 CFR 254.3) to 

include: 

(i) A discussion of your regional 

OSRP; 

(ii) The location of your primary oil 

spill equipment base and staging area; 

(iii) The name(s) of your oil spill 

removal organization(s) for both 

equipment and personnel; 

(iv) The calculated volume of your 

worst case discharge scenario (see 30 

CFR 254.26(a)), and a comparison of the 

appropriate worst case discharge 

scenario in your approved regional 

OSRP with the worst case discharge 

scenario that could result from your 

proposed development and production 

activities; and 

(v) A description of the worst case oil 

spill scenario that could result from 

your proposed development and 

production activities (see 30 CFR 

254.26(b), (c), (d), and (e)). 

(b) Modeling report. If you model a 

potential oil or hazardous substance 

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 timetable 

for acquiring lands (including rights-ofway and easements) and constructing or 

expanding any of the onshore support 

facilities. 

(b) Air emissions. A description of the 

source, composition, frequency, and 

duration of the air emissions 

(attributable to your proposed 

development and production activities) 

likely to be generated by the onshore 

support facilities you will use. 

(c) Unusual solid and liquid wastes. A 

description of the quantity, 

composition, and method of disposal of 

any unusual solid and liquid wastes 

(attributable to your proposed 

development and production activities) 

likely to be generated by the onshore 

support facilities you will use. Unusual 

wastes are those wastes not specifically 

addressed in the relevant National 

Pollution Discharge Elimination System 

(NPDES) permit. 

(d) Waste disposal. A description of 

the onshore facilities you will use to 

store and dispose of solid and liquid 

wastes generated by your proposed 

development and production activities 

(see § 550.248(a)) and the types and 

quantities of such wastes. 

§ 550.259 What sulphur operations 

information must accompany the DPP or 

DOCD? 

If you are proposing to conduct 

sulphur development and production 

activities, the following information 

must accompany your DPP or DOCD: 

(a) Bleedwater. A discussion of the 

bleedwater that will be generated by 

your proposed sulphur activities, 

including the measures you will take to 

mitigate the potential toxic or thermal 

impacts on the environment caused by 

the discharge of bleedwater. 

(b) Subsidence. An estimate of the 

degree of subsidence expected at 

various stages of your sulphur 

development and production activities, 

and a description of the measures you 

will take to mitigate the effects of 

subsidence on existing or potential oil 

and gas production, production 

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platforms, and production facilities, and 

to protect the environment. 

§ 550.260 What Coastal Zone Management 

Act (CZMA) information must accompany 

the DPP or DOCD? 

The following CZMA information 

must accompany your DPP or DOCD: 

(a) Consistency certification. A copy 

of your consistency certification under 

section 307(c)(3)(B) of the CZMA (16 

U.S.C. 1456(c)(3)(B)) and 15 CFR 

930.76(c) stating that the proposed 

development and production activities 

described in detail in this DPP or DOCD 

comply with (name of State(s)) 

approved coastal management 

program(s) and will be conducted in a 

manner that is consistent with such 

program(s); and 

(b) Other information. ‘‘Information’’ 

as required by 15 CFR 930.76(a) and 15 

CFR 930.58(a)(2)) and ‘‘Analysis’’ as 

required by 15 CFR 930.58(a)(3). 

§ 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 calendar 

days after receiving your deemedsubmitted DPP or DOCD to submit 

comments and recommendations. The 

Regional Supervisor will not consider 

comments and recommendations 

received after the deadline. 

(2) The executive of any affected local 

government who requests a copy. The 

executive of any affected local 

government has 60 calendar days after 

receipt of your deemed-submitted DPP 

or DOCD to submit comments and 

recommendations. The Regional 

Supervisor will not consider comments 

and recommendations received after the 

deadline. The executive of any affected 

local government must forward all 

comments and recommendations to the 

respective Governor before submitting 

them to the Regional Supervisor. 

(3) The CZMA agency of each affected 

State. The CZMA consistency review 

period under section 307(c)(3)(B)(ii) of 

the CZMA (16 U.S.C.1456(c)(3)(B)(ii)) 

and 15 CFR 930.78 begins when the 

States CZMA agency receives a copy of 

your deemed-submitted DPP or DOCD, 

consistency certification, and required 

necessary data/information (see 15 CFR 

930.77(a)(1)). 

(b) General public. Within 2 working 

days after the Regional Supervisor 

deems your DPP or DOCD submitted 

under § 550.266, the Regional 

Supervisor will make a public 

information copy of the DPP or DOCD 

and its accompanying information 

available for review to any appropriate 

interstate regional entity and the public 

at the appropriate BOEM Regional 

Public Information Office. Any 

interested Federal agency or person may 

submit comments and recommendations 

to the Regional Supervisor. Comments 

and recommendations must be received 

by the Regional Supervisor within 60 

calendar days after the DPP or DOCD 

including its accompanying information 

is made available. 

(c) BOEM compliance review. The 

Regional Supervisor will review the 

development and production activities 

in your proposed DPP or DOCD to 

ensure that they conform to the 

performance standards in § 550.202. 

(d) Amendments. During the review 

of your proposed DPP or DOCD, the 

Regional Supervisor may require you, or 

you may elect, to change your DPP or 

DOCD. If you elect to amend your DPP 

or DOCD, the Regional Supervisor may 

determine that your DPP or DOCD, as 

amended, is subject to the requirements 

of § 550.266. 

§ 550.268 How does BOEM respond to 

recommendations? 

(a) Governor. The Regional Supervisor 

will accept those recommendations 

from the Governor that provide a 

reasonable balance between the 

National interest and the well-being of 

the citizens of each affected State. The 

Regional Supervisor will explain in 

writing to the Governor the reasons for 

rejecting any of his or her 

recommendations. 

(b) Local governments and the public. 

The Regional Supervisor may accept 

recommendations from the executive of 

any affected local government or the 

public. 

(c) Availability. The Regional 

Supervisor will make all comments and 

recommendations available to the 

public upon request. 

§ 550.269 How will BOEM evaluate the 

environmental impacts of the DPP or 

DOCD? 

The Regional Supervisor will evaluate 

the environmental impacts of the 

activities described in your proposed 

DPP or DOCD and prepare 

environmental documentation under the 

National Environmental Policy Act 

(NEPA) (42 U.S.C.4321 et seq.) and the 

implementing regulations (40 CFR parts 

1500 through 1508). 

(a) Environmental impact statement 

(EIS) declaration. At least once in each 

OCS planning area (other than the 

Western and Central GOM Planning 

Areas), the Director will declare that the 

approval of a proposed DPP is a major 

Federal action, and BOEM will prepare 

an EIS. 

(b) Leases or units in the vicinity. 

Before or immediately after the Director 

determines that preparation of an EIS is 

required, the Regional Supervisor may 

require lessees and operators of leases or 

units in the vicinity of the proposed 

development and production activities 

for which DPPs have not been approved 

to submit information about preliminary 

plans for their leases or units. 

(c) Draft EIS. The Regional Supervisor 

will send copies of the draft EIS to the 

Governor of each affected State and to 

the executive of each affected local 

government who requests a copy. 

Additionally, when BOEM prepares a 

DPP EIS, and the Federally-approved 

CZMA program for an affected State 

requires a DPP NEPA document for use 

in determining consistency, the 

Regional Supervisor will forward a copy 

of the draft EIS to the State’s CZMA 

agency. The Regional Supervisor will 

also make copies of the draft EIS 

available to any appropriate Federal 

agency, interstate regional entity, and 

the public. 

§ 550.270 What decisions will BOEM make 

on the DPP or DOCD and within what 

timeframe? 

(a) Timeframe. The Regional 

Supervisor will act on your deemedsubmitted DPP or DOCD as follows: 

(1) The Regional Supervisor will make 

a decision within 60 calendar days after 

the latest of the day that: 

(i) The comment period provided in 

§ 550.267(a)(1), (a)(2), and (b) closes; 

(ii) The final EIS for a DPP is released 

or adopted; or 

(iii) The last amendment to your 

proposed DOCD is received by the 

Regional Supervisor. 

(2) Notwithstanding paragraph (a)(1) 

of this section, BOEM will not approve 

your DPP or DOCD until either: 

(i) All affected States with approved 

CZMA programs concur, or have been 

conclusively presumed to concur, with 

your DPP or DOCD consistency 

certification under section 

307(c)(3)(B)(i) and (ii) of the CZMA (16 

U.S.C. 1456(c)(3)(B)(i) and (ii)); or 

(ii) The Secretary of Commerce has 

made a finding authorized by section 

307(c)(3)(B)(iii) of the CZMA (16 U.S.C. 

1456(c)(3)(B)(iii)) that each activity 

described in the DPP or DOCD is 

consistent with the objectives of the 

CZMA, or is otherwise necessary in the 

interest of National security. 

(b) BOEM decision. By the deadline in 

paragraph (a) of this section, the 

Regional Supervisor will take one of the 

following actions: 

The regional supervisor will . . . If . . . And then . . . 

(1) Approve your DPP or DOCD, It complies with all applicable requirements, The Regional Supervisor will notify you in writing of the decision and 

may require you to meet certain conditions, including those to provide monitoring information. 

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The regional supervisor will . . . If . . . And then . . . 

(2) Require you to modify your proposed DPP or DOCD, It fails to make adequate provisions for safety, environmental 

protection, or conservation of 

natural resources or otherwise 

does not comply with the lease, 

the Act, the regulations prescribed under the Act, or other 

Federal laws, 

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 postapproval monitoring? 

After approving your EP, DPP, or 

DOCD, the Regional Supervisor may 

direct you to conduct monitoring 

programs, including monitoring in 

accordance with the ESA and the 

MMPA. You must retain copies of all 

monitoring data obtained or derived 

from your monitoring programs and 

make them available to the BOEM upon 

request. The Regional Supervisor may 

require you to: 

(a) Monitoring plans. Submit 

monitoring plans for approval before 

you begin the work; and 

(b) Monitoring reports. Prepare and 

submit reports that summarize and 

analyze data and information obtained 

or derived from your monitoring 

programs. The Regional Supervisor will 

specify requirements for preparing and 

submitting these reports. 

§ 550.283 When must I revise or 

supplement the approved EP, DPP, or 

DOCD? 

(a) Revised OCS plans. You must 

revise your approved EP, DPP, or DOCD 

when you propose to: 

(1) Change the type of drilling rig 

(e.g., jack-up, platform rig, barge, 

submersible, semisubmersible, or 

drillship), production facility (e.g., 

caisson, fixed platform with piles, 

tension leg platform), or transportation 

mode (e.g., pipeline, barge); 

(2) Change the surface location of a 

well or production platform by a 

distance more than that specified by the 

Regional Supervisor; 

(3) Change the type of production or 

significantly increase the volume of 

production or storage capacity; 

(4) Increase the emissions of an air 

pollutant to an amount that exceeds the 

amount specified in your approved EP, 

DPP, or DOCD; 

(5) Significantly increase the amount 

of solid or liquid wastes to be handled 

or discharged; 

(6) Request a new H2S area 

classification, or increase the 

concentration of H2S to a concentration 

greater than that specified by the 

Regional Supervisor; 

(7) Change the location of your 

onshore support base either from one 

State to another or to a new base or a 

base requiring expansion; or 

(8) Change any other activity specified 

by the Regional Supervisor. 

(b) Supplemental OCS plans. You 

must supplement your approved EP, 

DPP, or DOCD when you propose to 

conduct activities on your lease(s) or 

unit that require approval of a license or 

permit which is not described in your 

approved EP, DPP, or DOCD. These 

types of changes are called 

supplemental OCS plans. 

§ 550.284 How will BOEM require revisions 

to the approved EP, DPP, or DOCD? 

(a) Periodic review. The Regional 

Supervisor will periodically review the 

activities you conduct under your 

approved EP, DPP, or DOCD and may 

require you to submit updated 

information on your activities. The 

frequency and extent of this review will 

be based on the significance of any 

changes in available information and 

onshore or offshore conditions affecting, 

or affected by, the activities in your 

approved EP, DPP, or DOCD. 

(b) Results of review. The Regional 

Supervisor may require you to revise 

your approved EP, DPP, or DOCD based 

on this review. In such cases, the 

Regional Supervisor will inform you of 

the reasons for the decision. 

§ 550.285 How do I submit revised and 

supplemental EPs, DPPs, and DOCDs? 

(a) Submittal. You must submit to the 

Regional Supervisor any revisions and 

supplements to approved EPs, DPPs, or 

DOCDs for approval, whether you 

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initiate them or the Regional Supervisor 

orders them. 

(b) Information. Revised and 

supplemental EPs, DPPs, and DOCDs 

need include only information related to 

or affected by the proposed changes, 

including information on changes in 

expected environmental impacts. 

(c) Procedures. All supplemental EPs, 

DPPs, and DOCDs, and those revised 

EPs, DPPs, and DOCDs that the Regional 

Supervisor determines are likely to 

result in a significant change in the 

impacts previously identified and 

evaluated, are subject to all of the 

procedures under §§ 550.231 through 

550.235 for EPs and §§ 550.266 through 

550.273 for DPPs and DOCDs. 

§§ 550.286–550.295 [Reserved] 

Conservation Information Documents 

(CID) 

§ 550.296 When and how must I submit a 

CID or a revision to a CID? 

(a) You must submit one original and 

two copies of a CID to the appropriate 

OCS Region at the same time you first 

submit your DOCD or DPP for any 

development of a lease or leases located 

in water depths greater than 400 meters 

(1,312 feet). You must also submit a CID 

for a Supplemental DOCD or DPP when 

requested by the Regional Supervisor. 

The submission of your CID must be 

accompanied by payment of the service 

fee listed in § 550.125. 

(b) If you decide not to develop a 

reservoir you committed to develop in 

your CID, you must submit one original 

and two copies of a revision to the CID 

to the appropriate OCS Region. The 

revision to the CID must be submitted 

within 14 calendar days after making 

your decision not to develop the 

reservoir and before the reservoir is 

bypassed. The Regional Supervisor will 

approve or disapprove any such 

revision to the original CID. If the 

Regional Supervisor disapproves the 

revision, you must develop the reservoir 

as described in the original CID. 

§ 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 period 

when a well penetrating a hydrocarbonbearing structure reaches total depth 

during the evaluation period and the 

data from that well is needed for the 

CID. You will receive written 

notification from the Regional 

Supervisor describing the additional 

information that is needed, and the 

evaluation period will resume once 

BOEM receives the requested 

information. 

(c) The Regional Supervisor will 

approve or deny your CID request based 

on your commitment to develop 

economically producible reservoirs 

according to sound conservation, 

engineering, and economic practices. 

§ 550.299 What operations require 

approval of the CID? 

You may not begin production before 

you receive BOEM approval of the CID. 

Subpart C—Pollution Prevention and 

Control 

§§ 550.300–550.301 [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 

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energy, environmental and economic 

impacts, and other costs. The BACT 

shall be verified on a case-by-case basis 

by the Regional Supervisor and may 

include reductions achieved through the 

application of processes, systems, and 

techniques for the control of each air 

pollutant. 

Emission offsets mean emission 

reductions obtained from facilities, 

either onshore or offshore, other than 

the facility or facilities covered by the 

proposed Exploration Plan or 

Development and Production Plan. 

Existing facility is an OCS facility 

described in an Exploration Plan or a 

Development and Production Plan 

submitted or approved prior to June 2, 

1980. 

Facility means any installation or 

device permanently or temporarily 

attached to the seabed which is used for 

exploration, development, and 

production activities for oil, gas, or 

sulphur and which emits or has the 

potential to emit any air pollutant from 

one or more sources. All equipment 

directly associated with the installation 

or device shall be considered part of a 

single facility if the equipment is 

dependent on, or affects the processes 

of, the installation or device. During 

production, multiple installations or 

devices will be considered to be a single 

facility if the installations or devices are 

directly related to the production of oil, 

gas, or sulphur at a single site. Any 

vessel used to transfer production from 

an offshore facility shall be considered 

part of the facility while physically 

attached to it. 

Nonattainment area means, for any 

air pollutant, an area which is shown by 

monitored data or which is calculated 

by air quality modeling (or other 

methods determined by the 

Administrator of EPA to be reliable) to 

exceed any primary or secondary 

ambient air quality standard established 

by EPA. 

Projected emissions mean emissions, 

either controlled or uncontrolled, from 

a source(s). 

Source means an emission point. 

Several sources may be included within 

a single facility. 

Temporary facility means activities 

associated with the construction of 

platforms offshore or with facilities 

related to exploration for or 

development of offshore oil and gas 

resources which are conducted in one 

location for less than 3 years. 

Volatile organic compound (VOC) 

means any organic compound which is 

emitted to the atmosphere as a vapor. 

The unreactive compounds are exempt 

from the above definition. 

§ 550.303 Facilities described in a new or 

revised Exploration Plan or Development 

and Production Plan. 

(a) New plans. All Exploration Plans 

and Development and Production Plans 

shall include the information required 

to make the necessary findings under 

paragraphs (d) through (i) of this 

section, and the lessee shall comply 

with the requirements of this section as 

necessary. 

(b) Applicability of § 550.303 to 

existing facilities. (1) The Regional 

Supervisor may review any Exploration 

Plan or Development and Production 

Plan to determine whether any facility 

described in the plan should be subject 

to review under this section and has the 

potential to significantly affect the air 

quality of an onshore area. To make 

these decisions, the Regional Supervisor 

shall consider the distance of the facility 

from shore, the size of the facility, the 

number of sources planned for the 

facility and their operational status, and 

the air quality status of the onshore area. 

(2) For a facility identified by the 

Regional Supervisor in paragraph (b)(1) 

of this section, the Regional Supervisor 

shall require the lessee to refer to the 

information required in § 550.218 or 

§ 550.249 of this part and to submit only 

that information required to make the 

necessary findings under paragraphs (d) 

through (i) of this section. The lessee 

shall submit this information within 120 

days of the Regional Supervisor’s 

determination or within a longer period 

of time at the discretion of the Regional 

Supervisor. The lessee shall comply 

with the requirements of this section as 

necessary. 

(c) Revised facilities. All revised 

Exploration Plans and Development and 

Production Plans shall include the 

information required to make the 

necessary findings under paragraphs (d) 

through (i) of this section. The lessee 

shall comply with the requirements of 

this section as necessary. 

(d) Exemption formulas. To determine 

whether a facility described in a new, 

modified, or revised Exploration Plan or 

Development and Production Plan is 

exempt from further air quality review, 

the lessee shall use the highest annualtotal amount of emissions from the 

facility for each air pollutant calculated 

in § 550.249(a) or § 550.218(a) of this 

part and compare these emissions to the 

emission exemption amount ‘‘E’’ for 

each air pollutant calculated using the 

following formulas: E=3400D 2⁄3 for 

carbon monoxide (CO); and E=33.3D for 

total suspended particulates (TSP), 

sulphur dioxide (SO2), nitrogen oxides 

(NOX), and VOC (where E is the 

emission exemption amount expressed 

in tons per year, and D is the distance 

of the proposed facility from the closest 

onshore area of a State expressed in 

statute miles). If the amount of these 

projected emissions is less than or equal 

to the emission exemption amount ‘‘E’’ 

for the air pollutant, the facility is 

exempt from further air quality review 

required under paragraphs (e) through 

(i) of this section. 

(e) Significance levels. For a facility 

not exempt under paragraph (d) of this 

section for air pollutants other than 

VOC, the lessee shall use an approved 

air quality model to determine whether 

the projected emissions of those air 

pollutants from the facility result in an 

onshore ambient air concentration 

above the following significance levels: 

SIGNIFICANCE LEVELS—AIR POLLUTANT CONCENTRATIONS

[μg/m3] 

Air pollutant 

Averaging time (hours) 

Annual 24 8 3 1 

SO2 ....................................................................................... 1 5 ........................ 25 ........................

TSP ...................................................................................... 1 5 ........................ ........................ ........................

NO2 ...................................................................................... 1 ........................ ........................ ........................ ........................

CO ........................................................................................ ........................ ........................ 500 ........................ 2,000 

(f) Significance determinations. (1) 

The projected emissions of any air 

pollutant other than VOC from any 

facility which result in an onshore 

ambient air concentration above the 

significance level determined under 

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paragraph (e) of this section for that air 

pollutant, shall be deemed to 

significantly affect the air quality of the 

onshore area for that air pollutant. 

(2) The projected emissions of VOC 

from any facility which is not exempt 

under paragraph (d) of this section for 

that air pollutant shall be deemed to 

significantly affect the air quality of the 

onshore area for VOC. 

(g) Controls required. (1) The 

projected emissions of any air pollutant 

other than VOC from any facility, except 

a temporary facility, which significantly 

affect the quality of a nonattainment 

area, shall be fully reduced. This shall 

be done through the application of 

BACT and, if additional reductions are 

necessary, through the application of 

additional emission controls or through 

the acquisition of offshore or onshore 

offsets. 

(2) The projected emissions of any air 

pollutant other than VOC from any 

facility which significantly affect the air 

quality of an attainment or 

unclassifiable area shall be reduced 

through the application of BACT. 

(i) (A) Except for temporary facilities, 

the lessee also shall use an approved air 

quality model to determine whether the 

emissions of TSP or SO2 that remain 

after the application of BACT cause the 

following maximum allowable increases 

over the baseline concentrations 

established in 40 CFR 52.21 to be 

exceeded in the attainment or 

unclassifiable area: 

MAXIMUM ALLOWABLE CONCENTRATION INCREASES

[μg/m3] 

Air pollutant 

Averaging times 

Annual mean 1 24-hour 

maximum 

3-hour 

maximum 

Class I: 

TSP ....................................................................................................................................... 5 10 ........................

SO2 ....................................................................................................................................... 2 5 25 

Class II: 

TSP ....................................................................................................................................... 19 37 ........................

SO2 ....................................................................................................................................... 20 91 512 

Class III: 

TSP ....................................................................................................................................... 37 75 ........................

SO2 ....................................................................................................................................... 40 182 700 

1For TSP—geometric; For SO2—arithmetric. 

(B) No concentration of an air 

pollutant shall exceed the concentration 

permitted under the national secondary 

ambient air quality standard or the 

concentration permitted under the 

national primary air quality standard, 

whichever concentration is lowest for 

the air pollutant for the period of 

exposure. For any period other than the 

annual period, the applicable maximum 

allowable increase may be exceeded 

during one such period per year at any 

one onshore location. 

(ii) If the maximum allowable 

increases are exceeded, the lessee shall 

apply whatever additional emission 

controls are necessary to reduce or offset 

the remaining emissions of TSP or SO2

so that concentrations in the onshore 

ambient air of an attainment or 

unclassifiable area do not exceed the 

maximum allowable increases. 

(3)(i) The projected emissions of VOC 

from any facility, except a temporary 

facility, which significantly affect the 

onshore air quality of a nonattainment 

area shall be fully reduced. This shall be 

done through the application of BACT 

and, if additional reductions are 

necessary, through the application of 

additional emission controls or through 

the acquisition of offshore or onshore 

offsets. 

(ii) The projected emissions of VOC 

from any facility which significantly 

affect the onshore air quality of an 

attainment area shall be reduced 

through the application of BACT. 

(4)(i) If projected emissions from a 

facility significantly affect the onshore 

air quality of both a nonattainment and 

an attainment or unclassifiable area, the 

regulatory requirements applicable to 

projected emissions significantly 

affecting a nonattainment area shall 

apply. 

(ii) If projected emissions from a 

facility significantly affect the onshore 

air quality of more than one class of 

attainment area, the lessee must reduce 

projected emissions to meet the 

maximum allowable increases specified 

for each class in paragraph (g)(2)(i) of 

this section. 

(h) Controls required on temporary 

facilities. The lessee shall apply BACT 

to reduce projected emissions of any air 

pollutant from a temporary facility 

which significantly affects the air 

quality of an onshore area of a State. 

(i) Emission offsets. When emission 

offsets are to be obtained, the lessee 

must demonstrate that the offsets are 

equivalent in nature and quantity to the 

projected emissions that must be 

reduced after the application of BACT; 

a binding commitment exists between 

the lessee and the owner or owners of 

the source or sources; the appropriate 

air quality control jurisdiction has been 

notified of the need to revise the State 

Implementation Plan to include the 

information regarding the offsets; and 

the required offsets come from sources 

which affect the air quality of the area 

significantly affected by the lessee’s 

offshore operations. 

(j) Review of facilities with emissions 

below the exemption amount. If, during 

the review of a new, modified, or 

revised Exploration Plan or 

Development and Production Plan, the 

Regional Supervisor determines or an 

affected State submits information to the 

Regional Supervisor which 

demonstrates, in the judgment of the 

Regional Supervisor, that projected 

emissions from an otherwise exempt 

facility will, either individually or in 

combination with other facilities in the 

area, significantly affect the air quality 

of an onshore area, then the Regional 

Supervisor shall require the lessee to 

submit additional information to 

determine whether emission control 

measures are necessary. The lessee shall 

be given the opportunity to present 

information to the Regional Supervisor 

which demonstrates that the exempt 

facility is not significantly affecting the 

air quality of an onshore area of the 

State. 

(k) Emission monitoring requirements. 

The lessee shall monitor, in a manner 

approved or prescribed by the Regional 

Supervisor, emissions from the facility. 

The lessee shall submit this information 

monthly in a manner and form 

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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 = 3400D2/3for CO; 

and E = 33.3D for TSP, SO2, NOX, and 

VOC (where E is the emission 

exemption amount expressed in tons 

per year, and D is the distance of the 

facility from the closest onshore area of 

the State expressed in statute miles). If 

the amount of projected emissions is 

less than or equal to the emission 

exemption amount ‘‘E’’ for the air 

pollutant, the facility is exempt for that 

air pollutant from further air quality 

review required under paragraphs (c) 

through (e) of this section. 

(c) Significance levels. For a facility 

not exempt under paragraph (b) of this 

section for air pollutants other than 

VOC, the lessee shall use an approved 

air quality model to determine whether 

projected emissions of those air 

pollutants from the facility result in an 

onshore ambient air concentration 

above the following significance levels: 

SIGNIFICANCE LEVELS—AIR POLLUTANT CONCENTRATIONS

[μG/M3] 

Air pollutant 

Averaging time (hours) 

Annual 24 8 3 1 

SO2 ....................................................................................... 1 5 ........................ 25 ........................

TSP ...................................................................................... 1 5 ........................ ........................ ........................

NO2 ...................................................................................... 1 ........................ ........................ ........................ ........................

CO ........................................................................................ ........................ ........................ 500 ........................ 2,000 

(d) Significance determinations. 

(1) The projected emissions of any air 

pollutant other than VOC from any 

facility which result in an onshore 

ambient air concentration above the 

significance levels determined under 

paragraph (c) of this section for that air 

pollutant shall be deemed to 

significantly affect the air quality of the 

onshore area for that air pollutant. 

(2) The projected emissions of VOC 

from any facility which is not exempt 

under paragraph (b) of this section for 

that air pollutant shall be deemed to 

significantly affect the air quality of the 

onshore area for VOC. 

(e) Controls required. (1) The 

projected emissions of any air pollutant 

which significantly affect the air quality 

of an onshore area shall be reduced 

through the application of BACT. 

(2) The lessee shall submit a 

compliance schedule for the application 

of BACT. If it is necessary to cease 

operations to allow for the installation 

of emission controls, the lessee may 

apply for a suspension of operations 

under the provisions of 30 CFR 250.174. 

(f) Review of facilities with emissions 

below the exemption amount. If, during 

the review of the information required 

under paragraph (a)(6) of this section, 

the Regional Supervisor determines or 

an affected State submits information to 

the Regional Supervisor which 

demonstrates, in the judgment of the 

Regional Supervisor, that projected 

emissions from an otherwise exempt 

facility will, either individually or in 

combination with other facilities in the 

area, significantly affect the air quality 

of an onshore area, then the Regional 

Supervisor shall require the lessee to 

submit additional information to 

determine whether control measures are 

necessary. The lessee shall be given the 

opportunity to present information to 

the Regional Supervisor which 

demonstrates that the exempt facility is 

not significantly affecting the air quality 

of an onshore area of the State. 

(g) Emission monitoring requirements. 

The lessee shall monitor, in a manner 

approved or prescribed by the Regional 

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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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64660 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations 

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 penalty 

was assessed, that you want your leasespecific/area-wide bond on file to be 

used as the bond for the penalty 

amount. 

(c) If you choose the alternative in 

paragraph (b)(2) of this section, the 

BOEM Regional Director may require 

additional security (i.e., security in 

excess of your existing bond) to ensure 

sufficient coverage during an appeal. In 

that event, the Regional Director will 

require you to post the supplemental 

bond with the regional office in the 

same manner as under § 556.53(d) 

through (f) of this chapter. If the 

Regional Director determines the appeal 

should be covered by a lease-specific 

abandonment account then you must 

establish an account that meets the 

requirements of § 556.56. 

(d) If you do not either pay the 

penalty or file a timely appeal, BOEM 

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will take one or more of the following 

actions: 

(1) We will collect the amount you 

were assessed, plus interest, late 

payment charges, and other fees as 

provided by law, from the date you 

received the Reviewing Officer’s final 

decision until the date we receive 

payment; 

(2) We may initiate additional 

enforcement, including, if appropriate, 

cancellation of the lease, right-of-way, 

license, permit, or approval, or the 

forfeiture of a bond under this part; or 

(3) We may bar you from doing 

further business with the Federal 

Government according to Executive 

Orders 12549 and 12689, and section 

2455 of the Federal Acquisition 

Streamlining Act of 1994, 31 U.S.C. 

6101. The Department of the Interior’s 

regulations implementing these 

authorities are found at 43 CFR part 12, 

subpart D. 

Federal Oil and Gas Royalty 

Management Act Civil Penalties 

Definitions 

§ 550.1450 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 endanger 

operations under any lease, right-ofway, easement, right-of-use, Notice, or 

permit issued or maintained under the 

Act; 

(2) Cause harm or damage to life 

(including fish and other aquatic life), 

property, or to the marine, coastal, or 

human environment; 

(3) Cause harm or damage to any 

mineral resource (in areas leased or not 

leased); 

(4) Cause pollution; 

(5) Disturb archaeological resources; 

(6) Create hazardous or unsafe 

conditions; or 

(7) Unreasonably interfere with or 

cause harm to other uses of the area. 

(b) You must immediately report to 

the Regional Director if you: 

(1) Detect hydrocarbon occurrences; 

(2) Detect environmental hazards 

which imminently threaten life and 

property; or 

(3) Adversely affect the environment, 

aquatic life, archaeological resources, or 

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 to 

participate in the test activity on a costsharing basis. You may include a 

penalty provision for late participation 

of not more than 50 percent of the cost 

to each original participant in addition 

to the original share cost. 

(4) Procedures for group participation 

in drilling activities. You must: 

(i) Publish a summary statement that 

describes the approved activity in a 

relevant trade publication; 

(ii) Forward a copy of the published 

statement to the Regional Director; 

(iii) Allow at least 30 days from the 

summary statement publication date for 

other persons to join as original 

participants; 

(iv) Compute the estimated cost by 

dividing the estimated total cost of the 

program by the number of original 

participants; and 

(v) Furnish the Regional Director with 

a complete list of all participants before 

starting operations, or at the end of the 

advertising period if you begin 

operations before the advertising period 

is over. The names of any subsequent or 

late participants must also be furnished 

to the Regional Director. 

(5) Changes to the original application 

for test drilling. If you propose changes 

to the original application and the 

Regional Director determines that the 

changes are significant, the Regional 

Director will require you to publish the 

changes for an additional 30 days to 

give other persons a chance to join as 

original participants. 

(d) Bonding requirements. You must 

submit a bond under this part before 

you may start a deep stratigraphic test. 

(1) Before BOEM issues a permit 

authorizing the drilling of a deep 

stratigraphic test, you must either: 

(i) Furnish to BOEM a bond of not less 

than $200,000 that guarantees 

compliance with all the terms and 

conditions of the permit; or 

(ii) Maintain a $1 million bond that 

guarantees compliance with all the 

terms and conditions of the permit you 

hold for the OCS area where you 

propose to drill. 

(2) You must provide additional 

security to BOEM if the Regional 

Director determines that it is necessary 

for the permit or area. 

(3) The Regional Director may require 

you to provide a bond, in an amount the 

Regional Director prescribes, before 

authorizing you to drill a shallow test 

well. 

(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 BOEM 

approved the application for an extension. In any case BOEM will release the information no later than 50 years after BOEM issued the 

permit. 

(2) Permittees and third parties may 

apply to BOEM for an extension of the 

25-year proprietary term for geophysical 

information reprocessed 20 or more 

years after BOEM issued the germane 

permit. You must submit the 

application to BOEM within 90 days 

after completion of the reprocessing, 

except during the initial 1-year grace 

period as provided in paragraph (b)(5) 

below. Filing locations are listed in 

§ 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 

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maximum proprietary term for 

geophysical information is 50 years after 

the permit was issued. Once the 

maximum term is reached, the BOEM 

Regional Director will release the 

information to the public. 

(4) Geophysical information 

processed or reprocessed 20 or more 

years after the germane permit was 

issued and granted the extension will be 

subject to submission, inspection, and 

selection criteria under § 551.12 and 

reimbursement criteria identified under 

§ 551.13. 

(5) There was a 1-year grace period, 

that started September 14, 2009, that 

allowed permittees and third parties 

sufficient time to meet the above 

requirements and apply for all eligible 

extensions. During that time, BOEM did 

not release geophysical information 

which was reprocessed 20 or more years 

after the date that the germane permit 

was issued. 

(6) Since September 14, 2010, BOEM 

has resumed releasing eligible 

reprocessed information. If an 

application for extension was not filed, 

not filed on time, or not approved by 

BOEM, the original 25-year proprietary 

term applies to the release date of the 

reprocessed geophysical information. 

(7) If the data and information are 

related to a deep stratigraphic test, 

BOEM will release them to the public at 

the earlier of the following times: 

(i) Twenty-five years after you 

complete the test; or 

(ii) If a lease sale is held after you 

complete a test well, 60-calendar days 

after BOEM issues the first lease, any 

portion of which is located within 50 

geographic miles (92.7 kilometers) of the 

test. 

(8) BOEM may allow limited 

inspection, but only by persons with a 

direct interest in related BOEM 

decisions and issues in specific 

geographic areas, and who agree in 

writing to its confidentiality, of G&G 

data and information submitted under 

this part that BOEM uses to: 

(i) Make unitization determinations 

on two or more leases; 

(ii) Make competitive reservoir 

determinations; 

(iii) Ensure proper plans of 

development for competitive reservoirs; 

(iv) Promote operational safety; 

(v) Protect the environment; 

(vi) Make field determinations; or 

(vii) Determine eligibility for royalty 

relief. 

(c) Procedure that BOEM follows to 

disclose acquired data and information 

to a contractor for reproduction, 

processing, and interpretation. (1) When 

practical, the Regional Director will 

advise the person who submitted data 

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 

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completion of any means for the 

removal of oil or natural gas, including 

such removal, field operations, transfer 

of oil or natural gas to shore, operation 

monitoring, maintenance, and workover 

drilling. 

Secretary means the Secretary of the 

Interior or a designee of the Secretary. 

§ 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 

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for lease; and when available, projected 

rates and volumes of oil and gas to be 

produced from leased areas; 

(2) Magnitude of the approximate 

projections and timing of development, 

if and when oil or gas, or both, is 

discovered; 

(3) Methods of transportation to be 

used, including vessels and pipelines 

and approximate location of routes to be 

followed; and 

(4) General location and nature of 

near-shore and onshore facilities 

expected to be utilized. 

(b) When the Director determines that 

significant changes have occurred in the 

information contained in a Summary 

Report, the Director shall prepare and 

make available the new or revised 

information to each affected State, and, 

upon request, to the executive of any 

affected local government. 

§ 552.5 Information to be made available to 

affected States. 

(a) The Director shall prepare an 

index of OCS information (see 30 CFR 

556.10). The index shall list all relevant 

actual or proposed programs, plans, 

reports, environmental impact 

statements, nominations information, 

environmental study reports, lease sale 

information, and any similar type of 

relevant information, including 

modifications, comments, and revisions 

prepared or directly obtained by the 

Director under the Act. The index shall 

be sent to affected States and, upon 

request, to any affected local 

government. The public shall be 

informed of the availability of the index. 

(b) Upon request, the Director shall 

transmit to affected States, affected local 

governments, and the public a copy of 

any information listed in the index 

which is subject to the control of BOEM, 

in accordance with the requirements 

and subject to the limitations of the 

Freedom of Information Act (5 U.S.C. 

552) and implementing regulations. The 

Director shall not transmit or make 

available any information which he 

determines is exempt from disclosure in 

accordance with this part. 

§ 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 Geographic 

Names which contains the federallyrecognized geographic names for all 

known places, features, and areas in the 

United States that are identified by a 

proper name. Each feature is located by 

state, county, and geographic 

coordinates and is referenced to the 

appropriate 1:24,000-scale or 1:63,360- 

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. 

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(b) The designated applicant for a 

COF on a lease must be either: 

(1) A lessee; or 

(2) The designated operator for the 

OCS lease under 30 CFR 550.143 or the 

unit operator designated under a 

Federally approved unit including the 

OCS lease. For a lease or unit not in the 

OCS, the operator designated under the 

lease or unit operating agreement for the 

lease may be the designated applicant 

only if the operator has agreed to be 

responsible for compliance with all the 

laws and regulations applicable to the 

lease or unit. 

(c) The designated applicant for a 

COF on a permit must be the permittee. 

(d) The designated applicant for a 

COF on a RUE must be the holder of the 

RUE or, if there is a pipeline on the 

RUE, the owner or operator of the 

pipeline. 

(e) BOEM may require the designated 

applicant for a lease, permit, or RUE to 

be a person other than a person 

identified in paragraphs (b) through (d) 

of this section if BOEM determines that 

a person identified in paragraphs (b) 

through (d) cannot adequately 

demonstrate OSFR. 

(f) If you are a responsible party and 

you fail to designate an applicant, then 

you must demonstrate OSFR under the 

requirements of this part. 

§ 553.12 May I ask BOEM for a 

determination of whether I must 

demonstrate OSFR? 

You may submit to BOEM a request 

for a determination of OSFR 

applicability. Address the request to the 

office identified in § 553.45. You must 

include in your request any information 

that will assist BOEM in making the 

determination. BOEM may require you 

to submit other information before 

making a determination of OSFR 

applicability. 

§ 553.13 How much OSFR must I 

demonstrate? 

(a) The following general parameters 

apply to the amount of OSFR that you 

must demonstrate: 

If you are the designated applicant for . . . Then you must demonstrate . . . 

Only one COF, 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 selfinsurance as OSFR evidence? 

(a) You must submit a complete Form 

BOEM–1018 with each application to 

demonstrate OSFR using self-insurance. 

(b) You must submit your application 

to renew OSFR using self-insurance by 

the first calendar day of the 5th month 

after the close of your fiscal year. You 

may submit to BOEM your initial 

application to demonstrate OSFR using 

self-insurance at any time. 

§ 553.23 What information must I submit to 

support my net worth demonstration? 

You must support your net worth 

evaluation with information contained 

in your previous fiscal year’s audited 

annual financial statement. 

(a) Audited annual financial 

statements must be in the form of: 

(1) An annual report, prepared in 

accordance with the generally accepted 

accounting practices (GAAP) of the 

United States or other international 

accounting practices determined to be 

equivalent by BOEM; or 

(2) A Form 10–K or Form 20–F, 

prepared in accordance with Securities 

and Exchange Commission regulations. 

(b) Audited annual financial 

statements must be submitted together 

with a letter signed by your treasurer 

highlighting: 

(1) The State or the country of 

incorporation; 

(2) The total amount of the 

stockholders’ equity as shown on the 

balance sheet; 

(3) The net amount of the plant, 

property, and equipment shown on the 

balance sheet; and 

(4) The net amount of the identifiable 

U.S. assets and the identifiable total 

assets in the auditor’s notes to the 

financial statement (i.e., a geographic 

segmented business note). 

§ 553.24 When I submit audited annual 

financial statements to verify my net worth, 

what standards must they meet? 

(a) Your audited annual financial 

statements must be bound. 

(b) Your audited annual financial 

statements must include the unqualified 

opinion of an independent accountant 

that states: 

(1) The financial statements are free 

from material misstatement, and 

(2) The audit was conducted in 

accordance with the generally accepted 

auditing standards (GAAS) of the 

United States, or other international 

auditing standards that BOEM 

determines to be equivalent. 

(c) The financial information you 

submit must be expressed in U.S. 

dollars. If this information was 

originally reported in another form of 

currency, you must convert it to U.S. 

dollars using the conversion factor that 

was effective on the last day of the fiscal 

year pertinent to your financial 

statements. You also must identify the 

source of the currency exchange rate. 

§ 553.25 What financial test procedures 

must I use to determine the amount of selfinsurance allowed as OSFR evidence based 

on net worth? 

(a) Divide the total amount of the 

stockholders’/owners’ equity listed on 

the balance sheet by ten. 

(b) Divide the net amount of the 

identifiable U.S. assets by the net 

amount of the identifiable total assets. 

(c) Multiply the net amount of plant, 

property, and equipment shown on the 

balance sheet by the number calculated 

under paragraph (b) of this section and 

divide the resultant product by ten. 

(d) The smaller of the numbers 

calculated under paragraphs (a) or (c) of 

this section is the maximum allowable 

amount you may use to demonstrate 

OSFR under this method. 

§ 553.26 What information must I submit to 

support my unencumbered assets 

demonstration? 

You must support your 

unencumbered assets evaluation with 

the information required by § 553.23(a) 

and a list of reserved, unencumbered, 

and unimpaired U.S. assets whose value 

will not be affected by an oil discharge 

from a COF. The assets must be plant, 

property, or equipment held for use. 

You must submit a letter signed by your 

treasurer: 

(a) Identifying which assets are 

reserved; 

(b) Certifying that the assets are 

unencumbered, including contingent 

encumbrances; 

(c) Promising that the identified assets 

will not be sold, subjected to a security 

interest, or otherwise encumbered 

throughout the specified fiscal year; and 

(d) Specifying: 

(1) The State or the country of 

incorporation; 

(2) The total amount of the 

stockholders’/owners’ equity listed on 

the balance sheet; 

(3) The identification and location of 

the reserved U.S. assets; and 

(4) The value of the reserved U.S. 

assets less accumulated depreciation 

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and amortization, using the same 

valuation method used in your audited 

annual financial statement and 

expressed in U.S. dollars. The net value 

of the reserved assets must be at least 

two times the self-insurance amount 

requested for demonstration. 

§ 553.27 When I submit audited annual 

financial statements to verify my 

unencumbered assets, what standards 

must they meet? 

Any audited annual financial 

statements that you submit must: 

(a) Meet the standards in § 553.24; 

and 

(b) Include a certification by the 

independent accountant who audited 

the financial statements that states: 

(1) The value of the unencumbered 

assets is reasonable and uses the same 

valuation method used in your audited 

annual financial statements; 

(2) Any existing encumbrances are 

noted; 

(3) The assets are long-term assets 

held for use; and 

(4) The valuation method used in the 

audited annual financial statements is 

for long-term assets held for use. 

§ 553.28 What financial test procedures 

must I use to evaluate the amount of selfinsurance allowed as OSFR evidence based 

on unencumbered assets? 

(a) Divide the total amount of the 

stockholders’/owners’ equity listed on 

the balance sheet by 4. 

(b) Divide the value of the 

unencumbered U.S. assets by 2. 

(c) The smaller number calculated 

under paragraphs (a) or (b) of this 

section is the maximum allowable 

amount you may use to demonstrate 

OSFR under this method. 

§ 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 

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South; National City; Newport Beach; 

Oceano; Oceanside; Oxnard; Pismo Beach; 

Pitas Point; Point Arguello; Point 

Conception; Point Dune; Point Loma; Point 

Mugu; Point Sal; Port San Luis; Rancho Santa 

Fe; Redondo Beach; Sacate; San Clemente; 

San Juan Capistrano; San Luis Rey; San 

Onofre Bluff; San Pedro; Santa Barbara; 

Saticoy; Seal Beach; Surf; Tajiguas; Topanga; 

Torrance; Tranquillon Mountain; Triunfo 

Pass; Tustin; Venice; Ventura; White Ledge 

Peak. 

Florida (1:24,000 scale): Allanton; Alligator 

Bay; Anna Maria; Apalachicola; Aripeka; 

Bayport; Beacon Beach; Beacon Hill; Bee 

Ridge; Belle Meade; Belle Meade NW; 

Beverly; Big Lostmans Bay; Bird Keys; 

Bokeelia; Bonita Springs; Bradenton; 

Bradenton Beach; Bruce; Bunker; Cape 

Romano; Cape Saint George; Cape San Blas; 

Captiva; Carrabelle; Cedar Key; 

Chassahowitzka; Chassahowitzka Bay; 

Chiefland SW; Choctaw Beach; Chokoloskee; 

Clearwater; Clive Key; Cobb Rocks; 

Cockroach Bay; Crawfordville East; Crooked 

Island; Crooked Point; Cross City SW; Crystal 

River; Destin; Dog Island; Dunedin; East Pass; 

Egmont Key; El Jobean; Elfers; Englewood; 

Englewood NW; Estero; Everglades City; 

Fivay Junction; Flamingo; Fort Barrancas; 

Fort Myers Beach; Fort Myers SW; Fort 

Walton Beach; Freeport; Gandy Bridge; 

Garcon Point; Gator Hook Swamp; 

Gibsonton; Goose Island; Grayton Beach; 

Green Point; Gulf Breeze; Harney River; 

Harold SE; Holley; Holt SW; Homosassa; 

Horseshoe Beach; Indian Pass; Jackson River; 

Jena; Keaton Beach; Laguna Beach; Lake 

Ingraham East; Lake Ingraham West; Lake 

Wimico; Laurel; Lebanon Station; Lighthouse 

Point; Lillian; Long Point; Lostmans River 

Ranger Station; Manlin Hammock; Marco 

Island; Mary Esther; Matlacha; McIntyre; 

Milton South; Miramar Beach; Myakka River; 

Naples North; Naples South; Navarre; New 

Inlet; Niceville; Nutall Rise; Ochopee; 

Okefenokee Slough; Oldsmar; Orange Beach; 

Oriole Beach; Overstreet; Ozello; Pace; 

Palmetto; Panama City; Panama City Beach; 

Panther Key; Pass-A-Grille Beach; Pavillion 

Key; Pensacola; Perdido Bay; Pickett Bay; 

Pine Island Center; Placida; Plover Key; Point 

Washington; Port Boca Grande; Port Richey; 

Port Richey NE; Port Saint Joe; Port Tampa; 

Punta Gorda; Punta Gorda SE; Punta Gorda 

SW; Red Head; Red Level; Rock Islands; 

Royal Palm Hammock; Safety Harbor; Saint 

Joseph Point; Saint Joseph Spit; Saint Marks; 

Saint Marks NE; Saint Petersburg; Saint 

Teresa Beach; Salem SW; Sandy Key; 

Sanibel; Sarasota; Seahorse Key; Seminole; 

Seminole Hills; Shark Point; Shark River 

Island; Shired Island; Snipe Island; 

Sopchoppy; South of Holley; Southport; 

Sprague Island; Spring Creek; Springfield; 

Steinhatchee; Steinhatchee SE; Steinhatchee 

SW; Sugar Hill; Sumner; Suwannee; Tampa; 

Tarpon Springs; Valparaiso; Venice; Vista; 

Waccassasa Bay; Ward Basin; Warrior 

Swamp; Weavers Station; Weeki Wachee 

Spring; West Bay; West Pass; West Pensacola; 

Whitewater Bay West; Withlacoochee Bay; 

Wulfert; Yankeetown. 

Louisiana (1:24,000 scale): Alligator Point; 

Barataria Pass; Bastian Bay; Bay Batiste; Bay 

Coquette; Bay Courant; Bay Dosgris; Bay 

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 Act 

authorizes the Secretary to grant rightsof-way, rights-of-use and easements 

through the submerged lands of the 

OCS. The Energy Policy and 

Conservation Act of 1975 (42 U.S.C. 

6213), prohibits joint bidding by major 

oil and gas producers. 

§ 556.5 Definitions. 

As used in this part, the term: 

(a) Act refers to the Outer Continental 

Shelf Lands Act of August 7, 1953 (43 

U.S.C. 1331 et seq.) as amended. 

(b) Director means the Director, 

Bureau of Ocean Energy Management. 

(c) OCS means the Outer Continental 

Shelf, as that term is defined in 43 

U.S.C. 1331(a). 

(d) Secretary means the Secretary of 

the Interior or an official authorized to 

act on the Secretary’s behalf. 

(e) BOEM means Bureau of Ocean 

Energy Management. 

(f) Coastal zone means the coastal 

waters (including the lands therein and 

thereunder) and the adjacent shorelands 

(including the waters therein and 

thereunder), strongly influenced by each 

other and in proximity to the shorelines 

of the several coastal States, and 

includes islands, transition and 

intertidal areas, salt marshes, wetlands, 

and beaches, which zone extends 

seaward to the outer limit of the United 

States territorial sea and extends inland 

from the shore lines to the extent 

necessary to control shorelands, the 

uses of which have a direct and 

significant impact on the coastal waters, 

and the inward boundaries of which 

may be identified by the several coastal 

States, pursuant to the authority of 

section 305(b)(1) of the Coastal Zone 

Management Act of 1972 (16 U.S.C. 

1454(b)(1)); 

(g) Affected State means, with respect 

to any program, plan, lease sale, or other 

activity, proposed, conducted, or 

approved pursuant to the provisions of 

the act, any State: 

(1) The laws of which are declared, 

pursuant to section 4(a)(2) of the Act, to 

be the law of the United States for the 

portion of the Outer Continental Shelf 

on which such activity is, or is proposed 

to be conducted; 

(2) Which is, or is proposed to be, 

directly connected by transportation 

facilities to any artificial island or 

structure referred to in section 4(a)(1) of 

the Act; 

(3) Which is receiving, or in 

accordance with the proposed activity 

will receive, oil for processing, refining, 

or transshipment which was extracted 

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from the Outer Continental Shelf and 

transported directly to such State by 

means of vessels or by a combination of 

means including vessels; 

(4) Which is designated by the 

Secretary as a State in which there is a 

substantial probability of significant 

impact on or damage to the coastal, 

marine, or human environment, or a 

State in which there will be significant 

changes in the social, governmental, or 

economic infrastructure, resulting from 

the exploration, development, and 

production of oil and gas anywhere on 

the Outer Continental Shelf; or 

(5) In which the Secretary finds that 

because of such activity there is, or will 

be, a significant risk of serious damage, 

due to factors such as prevailing winds 

and currents, to the marine or coastal 

environment in the event of any oilspill, 

blowout, or release of oil or gas from 

vessels, pipelines, or other 

transshipment facilities; 

(h) Marine environment means the 

physical, atmospheric, and biological 

components, conditions, and factors 

which interactively determine the 

productivity, state, conditions, and 

quality of the marine ecosystem, 

including the waters of the high seas, 

the contiguous zone, transitional and 

intertidal areas, salt marshes, and 

wetlands within the coastal zone and on 

the Outer Continental Shelf; 

(i) Coastal environment means the 

physical, atmospheric, and biological 

components, conditions, and factors 

which interactively determine the 

productivity, state, conditions, and 

quality of the terrestrial ecosystem from 

the shoreline inward to the boundaries 

of the coastal zone; 

(j) Human environment means the 

physical, social, and economic 

components, conditions, and factors 

which interactively determine the state, 

condition, and quality of living 

conditions, employment, and health of 

those affected, directly or indirectly, by 

activities occurring on the Outer 

Continental Shelf; 

(k) Mineral means oil, gas, and 

sulphur; it includes sand and gravel and 

salt used to facilitate the development 

and production of oil, gas, or sulphur. 

(l) Authorized officer means any 

person authorized by law or by 

delegation of authority to or within 

BOEM to perform the duties described 

in this part. 

(m) Bonus or royalty credit means a 

legal instrument or other written 

documentation, or an entry in an 

account managed by the Secretary that 

a bidder or lessee may use in lieu of any 

other monetary payment for— 

(1) A bonus due for a lease on the 

Outer Continental Shelf; or 

(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, 

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production of crude oil, natural gas, or 

liquefied petroleum products and shall 

include, but not be limited to, a royalty 

interest, or overriding royalty interest, 

whether payable in cash or in kind, a 

working interest, a net profits interest, a 

production payment, or a carried 

interest. 

(g) Liquefied petroleum products 

means natural gas liquid products 

including the following: ethane, 

propane, butane, pentane, natural 

gasoline, and other natural gas products 

recovered by a process of absorption, 

adsorption, compression, or 

refrigeration cycling, or a combination 

of such processes. 

(h) Natural gas means a mixture of 

hydrocarbons and varying quantities of 

nonhydrocarbons that exist in the 

gaseous phase. 

(i) Oil and gas lease means an oil and 

gas lease either offered or issued 

pursuant to the provisions of the Act. 

(j) Owned means: 

(1) With respect to crude oil —having 

either an economic interest in or a 

power of disposition over the 

production of crude oil; 

(2) With respect to natural gas— 

having either an economic interest in or 

a power of disposition over the 

production of natural gas; and 

(3) With respect to liquefied 

petroleum products—having either an 

economic interest in or a power of 

disposition over any liquefied 

petroleum product at the time of 

completion of the liquefaction process. 

(k) Prior production period means the 

continuous 6-month period of January 1 

through June 30 preceding November 1 

through April 30 for joint bids 

submitted during the 6-month bidding 

period from November 1 through April 

30, and means the continuous 6-month 

period of July 1 through December 31 

preceding May 1 through October 31 for 

joint bids submitted during the 6-month 

bidding period from May 1 through 

October 31. 

(l) Production: (1) Of crude oil means 

the volume of crude oil produced 

worldwide from reservoirs during the 

prior production period. The amount of 

such crude oil production shall be 

established by measurement of volumes 

delivered at the point of custody 

transfer (e.g., from storage tanks to 

pipelines, trucks, tankers, or other 

media for transport to refineries or 

terminals) with adjustments for: 

(i) Net differences between opening 

and closing inventories, and 

(ii) Basic sediment and water; 

(2) Of natural gas means the volume 

of natural gas produced worldwide from 

natural oil and gas reservoirs during the 

prior production period, with 

adjustments, where applicable, to reflect 

(i) The volume of gas returned to 

natural reservoirs; and 

(ii) The reduction of volume resulting 

from the removal of natural gas liquids 

and nonhydrocarbon gases. 

(3) Of liquefied petroleum products 

mean the volume of natural gas liquids 

produced from reservoir gas and 

liquefied at surface separators, field 

facilities, or gas processing plants 

worldwide during the prior production 

period; these liquefied petroleum 

products include the following: 

(i) Condensate—natural gas liquids 

recovered from gas well gas (associated 

and non-associated) in separators or 

field facilities; 

(ii) Gas plant products—natural gas 

liquids recovered from natural gas in gas 

processing plants and from field 

facilities. Gas plant products shall 

include the following as classified 

according to the standards of the 

Natural Gas Processors Association 

(NGPA) or the American Society for 

Testing and Materials (ASTM): 

(A) Ethane—C2H6

(B) Propane—C3H8

(C) Butane—C4H10 including all 

products covered by NGPA 

specifications for commercial butane. 

(1) Isobutane, 

(2) Normal butane, 

(3) Other butanes—all butanes not 

included as isobutane or normal butane; 

(D) Butane-Propane Mixtures—All 

products covered by NGPA 

specifications for butane-propane 

mixtures; 

(E) Natural Gasoline—A mixture of 

hydrocarbons extracted from natural 

gas, which meet vapor pressure, end 

point, and other specifications for 

natural gasoline set by NGPA; 

(F) Plant Condensate—A natural gas 

plant product recovered and separated 

as a liquid at gas inlet separators or 

scrubbers in processing plants or field 

facilities; and 

(G) Other Natural Gas Plant Products 

meeting refined product standards (i.e., 

gasoline, kerosene, distillate, etc.). 

(m) 6-month bidding period means 

the 6-month period of time: 

(1) From May 1 through October 31; 

or 

(2) From November 1 through April 

30, respectively. 

§ 556.41 Joint bidding requirements. 

(a) Any person who submits a joint 

bid for any oil and gas lease during a 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 

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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 in 

any profit-sharing agreement, collateraltrust certificate, pre-organization 

certificate or subscription, transferable 

share, investment contract, voting-trust 

certificate, certificate of deposit for a 

security, fractional undivided interest in 

oil, gas, or other mineral rights, or, in 

general, any interest or instrument 

commonly known as a ‘‘security’’ or any 

certificate of interest or participation in, 

temporary or interim certificate for, 

receipt for, guarantee of, or warrant or 

right to subscribe to or purchase any of 

the foregoing. 

(b) A person filing a Statement of 

Production under § 556.41 of this part 

shall be charged with the following 

production during the applicable prior 

production period: 

(1) The average daily production in 

barrels of crude oil, natural gas, and 

liquefied petroleum products which it 

owned worldwide; 

(2) The average daily production in 

barrels of crude oil, natural gas, and 

liquefied petroleum products owned 

worldwide by every subsidiary of the 

reporting person; 

(3) The average daily production in 

barrels of crude oil, natural gas, and 

liquefied petroleum products owned 

worldwide by any person or persons of 

which the reporting person is a 

subsidiary; and 

(4) The average daily production in 

barrels of crude oil, natural gas, and 

liquefied petroleum products owned 

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 

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bid deposit amount and method of 

payment. 

(c) If the bidder is an individual a 

statement of citizenship shall 

accompany the bid. 

(d) If the bidder is an association 

(including a partnership), the bid shall 

be accompanied by a certified statement 

indicating the State in which it is 

registered and that it is authorized to 

hold mineral leases on the OCS, or 

appropriate reference to statements or 

records previously submitted to a BOEM 

OCS office (including material 

submitted in compliance with prior 

regulations). 

(e) If the bidder is a corporation, the 

following information shall be 

submitted with the bid: 

(1) A statement certified by the 

corporate Secretary or Assistant 

Secretary over the corporate seal 

showing the State in which it was 

incorporated and that it is authorized to 

hold mineral leases on the OCS, or 

appropriate reference to statements or 

records previously submitted to a BOEM 

OCS office (including material 

submitted in compliance with prior 

regulations). 

(2) Evidence of authority of persons 

signing to bind the corporation. Such 

evidence may be in the form of either 

a certified copy of the minutes of the 

board of directors or of the bylaws 

indicating that the person signing has 

authority to do so; or a certificate to that 

effect signed by the Secretary or 

Assistant Secretary of the corporation 

over the corporate seal, or appropriate 

reference to statements or records 

previously submitted to a BOEM OCS 

office (including material submitted in 

compliance with prior regulations). 

Bidders are advised to keep their filings 

current. 

(3) The bid shall be executed in 

conformance with corporate 

requirements. 

(f) Bidders should be aware of the 

provisions of 18 U.S.C. 1860, 

prohibiting unlawful combination or 

intimidation of bidders. 

(g) To verify the accuracy of any 

statement submitted pursuant to 

§ 556.41 of this part, the Director may 

require the person submitting such 

information to: 

(1) Submit no later than 30 days after 

receipt of the request by the Director, a 

detailed Report of Production which 

shall list, in barrels, the average daily 

production of crude oil, natural gas and 

liquefied petroleum products chargeable 

to the reporting person in accordance 

with § 556.43 of this part for the prior 

production period, and 

(2) Permit the inspection and copying 

by an official of the Department of the 

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 

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lessee on the OCS for the area in which 

the lease is situated. 

(c) When a lessee can demonstrate to 

the satisfaction of the authorized officer 

that wells and platforms can be 

abandoned and removed and the 

drilling and platform sites cleared of 

obstructions for less than the amount of 

lease bond coverage required under 

paragraph (b)(1) of this section, the 

authorized officer may accept a lease 

surety bond in an amount less than the 

prescribed amount but not less than the 

amount of the cost for well 

abandonment, platform removal, and 

site clearance. 

(d) The Regional Director may 

determine that additional security (i.e., 

security above the amounts prescribed 

in §§ 556.52(a) and 556.53(a) and (b) of 

this part) is necessary to ensure 

compliance with the obligations under 

your lease and the regulations in this 

chapter. 

(1) The Regional Director’s 

determination will be based on his/her 

evaluation of your ability to carry out 

present and future financial obligations 

demonstrated by: 

(i) Financial capacity substantially in 

excess of existing and anticipated lease 

and other obligations, as evidenced by 

audited financial statements (including 

auditor’s certificate, balance sheet, and 

profit and loss sheet); 

(ii) Projected financial strength 

significantly in excess of existing and 

future lease obligations based on the 

estimated value of your existing OCS 

lease production and proven reserves of 

future production; 

(iii) Business stability based on 5 

years of continuous operation and 

production of oil and gas or sulphur in 

the OCS or in the onshore oil and gas 

industry; 

(iv) Reliability in meeting obligations 

based on: 

(A) Credit rating(s); or 

(B) Trade references, including names 

and addresses of other lessees, drilling 

contractors, and suppliers with whom 

you have dealt; and 

(v) Record of compliance with laws, 

regulations, and lease terms. 

(2) You may satisfy the Regional 

Director’s demand for additional 

security by increasing the amount of 

your existing bond or by providing a 

supplemental bond or bonds. 

(e) The Regional Director will 

determine the amount of supplemental 

bond required to guarantee compliance. 

The Regional Director will consider 

potential underpayment of royalty and 

cumulative obligations to abandon 

wells, remove platforms and facilities, 

and clear the seafloor of obstructions in 

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 may 

authorize you to establish a leasespecific abandonment account in a 

federally insured institution in lieu of 

the bond required under § 556.53(d). 

The account must provide that, except 

as provided in paragraph (a)(3) of this 

section, funds may not be withdrawn 

without the written approval of the 

Regional Director. 

(1) Funds in a lease-specific 

abandonment account must be payable 

upon demand to BOEM and pledged to 

meet the lessee’s obligations under 30 

CFR 250.1703. 

(2) You must fully fund the leasespecific abandonment account to cover 

all the costs of lease abandonment and 

site clearance as estimated by BOEM 

within the timeframe the Regional 

Director prescribes. 

(3) You must provide binding 

instructions under which the institution 

managing the account is to purchase 

Treasury securities pledged to BOEM 

under paragraph (d) of this section. 

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(b) Any interest paid on funds in a 

lease-specific abandonment account 

will be treated as other funds in the 

account unless the Regional Director 

authorizes in writing the payment of 

interest to the party who deposits the 

funds. 

(c) The Regional Director may allow 

you to pledge Treasury securities that 

are made payable upon demand to the 

Regional Director to satisfy your 

obligation to make payments into a 

lease-specific abandonment account. 

(d) Before the amount of funds in a 

lease-specific abandonment account 

equals the maximum insurable amount 

as determined by the Federal Deposit 

Insurance Corporation or the Federal 

Savings and Loan Insurance 

Corporation, the institution managing 

the account must use the funds in the 

account to purchase Treasury securities 

pledged to BOEM under paragraph (c) of 

this section. The institution managing 

the lease specific-abandonment account 

will join with the Regional Director to 

establish a Federal Reserve Circular 154 

account to hold these Treasury 

securities, unless the Regional Director 

authorizes the managing institution to 

retain the pledged Treasury securities in 

a separate trust account. You may obtain 

a copy of the current Treasury Circular 

No. 154 from the Surety Bond Branch, 

Financial Management Service, 

Department of the Treasury, East-West 

Highway, Hyattsville, MD 20782. 

(e) The Regional Director may require 

you to create an overriding royalty or 

production payment obligation for the 

benefit of a lease-specific account 

pledged for the abandonment and 

clearance of a lease. The required 

obligation may be associated with oil 

and gas or sulphur production from a 

lease other than the lease bonded 

through the lease-specific abandonment 

account. 

§ 556.57 Using a third-party guarantee 

instead of a bond. 

(a) When the Regional Director may 

accept a third-party guarantee. The 

Regional Director may accept a thirdparty guarantee instead of an additional 

bond under § 556.53(d) if: 

(1) The guarantee meets the criteria in 

paragraph (c) of this section; 

(2) The guarantee includes the terms 

specified in paragraph (d) of this 

section; 

(3) The guarantor’s total outstanding 

and proposed guarantees do not exceed 

25 percent of its unencumbered net 

worth in the United States; and 

(4) The guarantor submits an 

indemnity agreement meeting the 

criteria in paragraph (e) of this section. 

(b) What to do if your guarantor 

becomes unqualified. If, during the life 

of your third-party guarantee, your 

guarantor no longer meets the criteria of 

paragraphs (a)(3) and (c)(3) of this 

section, you must: 

(1) Notify the Regional Director 

immediately; and 

(2) Cease production until you 

comply with the bond coverage 

requirements of this subpart. 

(c) Criteria for acceptable guarantees. 

If you propose to furnish a third party’s 

guarantee, that guarantee must ensure 

compliance with all lessees’ lease 

obligations, the obligations of all 

operating rights owners, and the 

obligations of all operators on the lease. 

The Regional Director will base 

acceptance of your third-party guarantee 

on the following criteria: 

(1) The period of time that your thirdparty guarantor (guarantor) has been in 

continuous operation as a business 

entity where: 

(i) Continuous operation is the time 

that your guarantor conducts business 

immediately before you post the 

guarantee; and 

(ii) Continuous operation excludes 

periods of interruption in operations 

that are beyond your guarantor’s control 

and that do not affect your guarantor’s 

likelihood of remaining in business 

during exploration, development, 

production, abandonment, and 

clearance operations on your lease. 

(2) Financial information available in 

the public record or submitted by your 

guarantor, on your guarantor’s own 

initiative, in sufficient detail to show to 

the Regional Director’s satisfaction that 

your guarantor is qualified based on: 

(i) Your guarantor’s current rating for 

its most recent bond issuance by either 

Moody’s Investor Service or Standard 

and Poor’s Corporation; 

(ii) Your guarantor’s net worth, taking 

into account liabilities under its 

guarantee of compliance with all the 

terms and conditions of your lease, the 

regulations in this chapter, and your 

guarantor’s other guarantees; 

(iii) Your guarantor’s ratio of current 

assets to current liabilities, taking into 

account liabilities under its guarantee of 

compliance with all the terms and 

conditions of your lease and the 

regulations in this chapter and your 

guarantor’s other guarantees; and 

(iv) Your guarantor’s unencumbered 

fixed assets in the United States. 

(3) When the information required by 

paragraph (c) of this section is not 

publicly available, your guarantor may 

submit the information in the following 

table. Your guarantor must update the 

information annually within 90 days of 

the end of the fiscal year or by the date 

prescribed by the Regional Director. 

The guarantor should submit . . . That . . . 

(i) Financial statements for the most recently completed fiscal year, Include a report by an independent certified public accountant containing the accountant’s audit opinion or review opinion of the statements. The report must be prepared in conformance with generally 

accepted accounting principles and contain no adverse opinion. 

(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 

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the termination of the period of liability 

under your third-party guarantee. 

(e) Required criteria for indemnity 

agreements. If the Regional Director 

approves your third-party guarantee, the 

guarantor must submit an indemnity 

agreement. 

(1) The indemnity agreement must be 

executed by your guarantor and all 

persons and parties bound by the 

agreement. 

(2) The indemnity agreement must 

bind each person and party executing 

the agreement jointly and severally. 

(3) When a person or party bound by 

the indemnity agreement is a corporate 

entity, two corporate officers who are 

authorized to bind the corporation must 

sign the indemnity agreement. 

(4) Your guarantor and the other 

corporate entities bound by the 

indemnity agreement must provide the 

Regional Director copies of: 

(i) The authorization of the signatory 

corporate officials to bind their 

respective corporations; 

(ii) An affidavit certifying that the 

agreement is valid under all applicable 

laws; and 

(iii) Each corporation’s corporate 

authorization to execute the indemnity 

agreement. 

(5) If your third-party guarantor or 

another party bound by the indemnity 

agreement is a partnership, joint 

venture, or syndicate, the indemnity 

agreement must: 

(i) Bind each partner or party who has 

a beneficial interest in your guarantor; 

and 

(ii) Provide that, upon demand by the 

Regional Director under your third-party 

guarantee, each partner is jointly and 

severally liable for compliance with all 

terms and conditions of your lease. 

(6) When forfeiture is called for under 

§ 556.59 of this part, the indemnity 

agreement must provide that your 

guarantor will either: 

(i) Bring your lease into compliance; 

or 

(ii) Provide, within 7 calendar days, 

sufficient funds to permit the Regional 

Director to complete corrective action. 

(7) The indemnity agreement must 

contain a confession of judgment. It 

must provide that, if the Regional 

Director determines that you, your 

operator, or an operating rights owner is 

in default of the lease, the guarantor: 

(i) Will not challenge the 

determination; and 

(ii) Will remedy the default. 

(8) Each indemnity agreement is 

deemed to contain all terms and 

conditions contained in this paragraph 

(e), even if the guarantor has omitted 

them. 

§ 556.58 Termination of the period of 

liability and cancellation of a bond. 

This section defines the terms and 

conditions under which BOEM will 

terminate the period of liability of a 

bond or cancel a bond. Terminating the 

period of liability of a bond ends the 

period during which obligations 

continue to accrue but does not relieve 

the surety of the responsibility for 

obligations that accrued during the 

period of liability. Canceling a bond 

relieves the surety of all liability. The 

liabilities that accrue during a period of 

liability include obligations that started 

to accrue prior to the beginning of the 

period of liability and had not been met 

and obligations that begin accruing 

during the period of liability. 

(a) When the surety under your bond 

requests termination: 

(1) The Regional Director will 

terminate the period of liability under 

your bond within 90 days after BOEM 

receives the request; and 

(2) If you intend to continue 

operations, or have not met all end of 

lease obligations, you must provide a 

replacement bond of an equivalent 

amount. 

(b) If you provide a replacement bond, 

the Regional Director will cancel your 

previous bond and the surety that 

provided your previous bond will not 

retain any liability, provided that: 

(1) The new bond is equal to or 

greater than the bond that was 

terminated, or you provide an 

alternative form of security, and the 

Regional Director determines that the 

alternative form of security provides a 

level of security equal to or greater than 

that provided for by the bond that was 

terminated; 

(2) For a base bond submitted under 

§ 556.52(a) or under § 556.53(a) or (b), 

the surety issuing the new bond agrees 

to assume all outstanding liabilities that 

accrued during the period of liability 

that was terminated; and 

(3) For supplemental bonds submitted 

under § 556.53(d), the surety issuing the 

new supplemental bond agrees to 

assume that portion of the outstanding 

liabilities that accrued during the period 

of liability which was terminated and 

that the Regional Director determines 

may exceed the coverage of the base 

bond, and of which the Regional 

Director notifies the provider of the 

bond. 

(c) This paragraph applies if the 

period of liability is terminated for a 

bond but the bond is not replaced by a 

bond of an equivalent amount. The 

surety that provided your terminated 

bond will continue to be responsible for 

accrued obligations: 

(1) Until the obligations are satisfied; 

and 

(2) For additional periods of time in 

accordance with paragraph (d) of this 

section. 

(d) When your lease expires or is 

terminated, the surety that issued a 

bond will continue to be responsible, 

and the Regional Director will retain 

other forms of security as shown in the 

following table: 

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 the 

lease, 6 years after completion of all bonded obligations, or at the conclusion of any 

appeals or litigation related to your bonded 

obligation, whichever is the latest. The Regional Director will reduce the amount of 

your bond or return a portion of your security if the Regional Director determines that 

you need less than the full amount of the 

base bond to meet any possible future 

problems. 

(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 

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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 

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require you to bring the lease into 

compliance to the extent that the 

obligation accrued before the Regional 

Director approved the assignment of 

your interest in the lease. 

§ 556.63 Service fees. 

(a) The table in this paragraph (a) 

shows the fees that you must pay to 

BOEM for the services listed. The fees 

will be adjusted periodically according 

to the Implicit Price Deflator for Gross 

Domestic Product by publication of a 

document in the Federal Register. If a 

significant adjustment is needed to 

arrive at the new actual cost for any 

reason other than inflation, then a 

proposed rule containing the new fees 

will be published in the Federal 

Register for comment. 

SERVICE FEE TABLE

Service Fee amount 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: 

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(i) The obligation relates to the area 

embraced by the sublease; 

(ii) Those owners held their 

respective interest at the time the 

obligation accrued; and 

(iii) This chapter does not provide 

otherwise. 

(i) Where the proposed assignment or 

transfer is by a person who, at the time 

of acquisition of an interest in the lease, 

was on the List of Restricted Joint 

Bidders, and that assignment or transfer 

is of less than the entire interest of the 

assignor or transferor, to a person or 

persons on the same List of Restricted 

Joint Bidders, the assignor or transferor 

shall file a copy, prior to approval of the 

assignment, of all agreements applicable 

to the acquisition of that lease or a 

fractional interest. 

§ 556.65 Attorney General review. 

Prior to the approval of an assignment 

or transfer, the Secretary shall consult 

with and give due consideration to the 

views of the Attorney General. The 

Secretary may act on an assignment or 

transfer if the Attorney General has not 

responded to the request for 

consultation within 30 days of said 

request. 

§ 556.67 Separate filings for assignments. 

A separate instrument of assignment 

shall be filed for each lease. When 

transfers to the same person, association 

or corporation, involving more than one 

lease are filed at the same time for 

approval, one request for approval and 

one showing as to the qualifications of 

the assignee shall be sufficient. 

§ 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. 

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(b) A lease maintained under section 

6(a) of the Act shall also be subject to 

all operating and conservation 

regulations applicable to the OCS. In 

addition, the regulations relating to 

geophysical and geological exploratory 

operations and to pipeline rights-of-way 

are applicable, to the extent that those 

regulations are not contrary to or 

inconsistent with the lease provisions 

relating to area, the minerals, rentals, 

royalties and term. The lessee shall 

comply with any provision of the lease 

as validated, the subject matter of which 

is not covered in the regulations in this 

part. 

§ 556.80 Leases of other minerals. 

The existence of a lease that meets the 

requirements of section 6(a) of the Act 

shall not preclude the issuance of other 

leases of the same area for deposits of 

other minerals. However, no other lease 

of minerals shall authorize or permit the 

lessee thereunder unreasonably to 

interfere with or endanger operations 

under the existing lease. No sulphur 

leases shall be granted by the United 

States on any area while such area is 

included in a lease covering sulphur 

under section 6(b) of the Act. 

Subpart M—Studies 

§ 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 FEDERAL REGISTER. 

(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 of 

production. Notwithstanding suspensions or deferrals, we may impose a minimum royalty. The suspensions or deferrals may vary 

based on prices or price changes of oil and/or gas. 

(2) You may pay a royalty rate less than 12.5 percent on production 

but not less than zero percent. 

(3) We will specify the applicable royalty rates(s) and suspension or 

deferral magnitudes, formulas, or relationships in the Notice of 

OCS Lease Sale published in the Federal Register. 

(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 FEDERAL REGISTER. 

(g) Cash bonus with a fixed royalty 

rate of not less than 12.5 percent, at the beginning of the 

lease period, suspension of royalties for a period, volume, or 

value of production, or depending 

upon selected characteristics of 

extraction, and with suspensions 

that may vary based on the price 

of production, 

Cash bonus, 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 

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designate a new field and will notify 

you and other affected lessees and 

operating rights holders in the field of 

that assignment. 

(1) Within 15 days of the final 

notification, you or any of the other 

affected lessees or operating rights 

holders may file a written request with 

the Director for reconsideration, 

accompanied by a Statement of Reasons. 

(2) The Director will respond in 

writing either affirming or reversing the 

assignment decision. The Director’s 

decision is the final action of the 

Department of the Interior and is not 

subject to appeal to the Interior Board of 

Land Appeals under 30 CFR part 590 

and 43 CFR part 4. 

(b) If we establish a royalty 

suspension volume for a field as a result 

of an approved application for royalty 

relief submitted for a pre-Act lease 

under 30 CFR part 203, then: 

(1) Royalty-free production from your 

RS lease shares from and counts as part 

of any royalty suspension volume under 

§ 560.114(d) for the field to which we 

assign your lease; and 

(2) Your RS lease may continue to 

produce royalty-free up to the royalty 

suspension we specified for your lease, 

even if the field to which we assign your 

RS lease has produced all of its royalty 

suspension volume. 

(c) Your lease may share in a 

suspension volume larger than the 

royalty suspension with which we 

issued it and to the extent we grant a 

larger volume in response to an 

application by a pre-Act lease submitted 

under 30 CFR part 203. To share in any 

larger royalty suspension volume, you 

must file an application described in 30 

CFR part 203 (§§ 203.71 and 203.83). In 

no case will royalty-free production for 

your RS lease be less than the royalty 

suspension specified for your lease. 

Bidding System Selection Criteria 

§ 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, 

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or other official acting in a similar 

capacity for such company. 

Subcontract means any business 

agreement or arrangement (in which the 

parties do not stand in the relationship 

of employer and employee) between a 

lessee’s contractor and any person other 

than a lessee that is in any way related 

to the performance of any one or more 

contracts. 

§ 570.4 Discrimination prohibited. 

No contract or subcontract to which 

this part applies shall be denied to or 

withheld from any person on the 

grounds of race, creed, color, national 

origin, or sex. 

§ 570.5 Complaint. 

(a) Whenever any person believes that 

he or she has been denied a contract or 

subcontract to which this part applies 

on the grounds of race, creed, color, 

national origin, or sex, such person may 

complain of such denial or withholding 

to the Regional Director of the OCS 

Region in which such action is alleged 

to have occurred. Any complaint filed 

under this part must be submitted in 

writing to the appropriate Regional 

Director not later than 180 days after the 

date of the alleged unlawful denial of a 

contract or subcontract which is the 

basis of the complaint. 

(b) The complaint referred to in 

paragraph (a) of this section shall be 

accompanied by such evidence as may 

be available to a person and which is 

relevant to the complaint including 

affidavits and other documents. 

(c) Whenever any person files a 

complaint under this part, the Regional 

Director with whom such complaint is 

filed shall give written notice of such 

filing to all persons cited in the 

complaint no later than 10 days after 

receipt of such complaint. Such notice 

shall include a statement describing the 

alleged incident of discrimination, 

including the date and the names of 

persons involved in it. 

§ 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 term 

includes oil, gas, sulphur, geopressuredgeothermal and associated resources. 

Notice means a written statement of 

intent to conduct G&G scientific 

research that is: 

(1) Related to hard minerals on the 

OCS; and 

(2) Not covered under a permit. 

Oil, gas, and sulphur means oil, gas, 

and sulphur, geopressured-geothermal 

and associated resources, including gas 

hydrates. 

Outer Continental Shelf (OCS) means 

all submerged lands: 

(1) That lie seaward and outside of the 

area of lands beneath navigable waters 

as defined in section 2 of the Submerged 

Lands Act (43 U.S.C. 1301); and 

(2) Whose subsoil and seabed belong 

to the United States and are subject to 

its jurisdiction and control. 

Permit means the contract or 

agreement, other than a lease, issued 

under this part. The permit gives a 

person the right, under appropriate 

statutes, regulations, and stipulations, to 

conduct on the OCS: 

(1) Geological prospecting for hard 

minerals; 

(2) Geophysical prospecting for hard 

minerals; 

(3) Geological scientific research; or 

(4) Geophysical scientific research. 

Permittee means the person 

authorized by a permit issued under this 

part to conduct activities on the OCS. 

Person means: 

(1) A citizen or national of the United 

States; 

(2) An alien lawfully admitted for 

permanent residence in the United 

States as defined in section 8 U.S.C. 

1101(a)(20); 

(3) A private, public, or municipal 

corporation organized under the laws of 

the United States or of any State or 

territory thereof, and association of such 

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citizens, nationals, resident aliens or 

private, public, or municipal 

corporations, States, or political 

subdivisions of States; or 

(4) Anyone operating in a manner 

provided for by treaty or other 

applicable international agreements. 

The term does not include Federal 

agencies. 

Processed geological or geophysical 

information means data collected under 

a permit and later processed or 

reprocessed. 

(1) Processing involves changing the 

form of data as to facilitate 

interpretation. Some examples of 

processing operations may include, but 

are not limited to: 

(i) Applying corrections for known 

perturbing causes; 

(ii) Rearranging or filtering data; and 

(iii) Combining or transforming data 

elements. 

(2) Reprocessing is the additional 

processing other than ordinary 

processing used in the general course of 

evaluation. Reprocessing operations 

may include varying identified 

parameters for the detailed study of a 

specific problem area. 

Secretary means the Secretary of the 

Interior or a subordinate authorized to 

act on the Secretary’s behalf. 

Shallow test drilling means drilling 

into the sea bottom to depths less than 

those specified in the definition of a 

deep stratigraphic test. 

Significant archaeological resource 

means those archaeological resources 

that meet the criteria of significance for 

eligibility of the National Register of 

Historic Places as defined in 36 CFR 

60.4, or its successor. 

Third party means any person other 

than the permittee or a representative of 

the United States, including all persons 

who obtain data or information acquired 

under a permit from the permittee, or 

from another third party, by sale, trade, 

license agreement, or other means. 

You means a person who applies for 

and/or obtains a permit, or files a notice 

to conduct G&G prospecting or scientific 

research related to hard minerals on the 

OCS. 

§ 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 endanger 

operations under any lease, right-ofway, easement, right-of-use, notice, or 

permit issued or maintained under the 

Act; 

(b) Cause harm or damage to life 

(including fish and other aquatic life), 

property, or the marine, coastal, or 

human environment; 

(c) Cause harm or damage to any 

mineral resources (in areas leased or not 

leased); 

(d) Cause pollution; 

(e) Disturb archaeological resources; 

(f) Create hazardous or unsafe 

conditions; 

(g) Unreasonably interfere with or 

cause harm to other uses of the area; or 

(h) Claim any oil, gas, sulphur, or 

other minerals you discover while 

conducting operations under a permit or 

notice. 

§ 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 paragraph (b) of this section apply. 

(b) This paragraph applies if you are 

covered by paragraph (a)(4) of this 

section and a lease sale is held or a 

noncompetitive agreement is negotiated 

after you complete a test well. We will 

release the data and information related 

to the deep stratigraphic test at the 

earlier of the following times: 

(1) Twenty-five years after you 

complete the test; or 

(2) Sixty calendar days after we issue 

a lease, located partly or totally within 

50 geographic miles (92.7 kilometers) of 

the test. 

§ 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, 

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and time specified in the leasing notice. 

The sole purpose of opening bids is to 

publicly announce and record the bids 

received, and no bids shall be accepted 

or rejected at that time. 

(2) The Secretary reserves the right to 

reject any and all sealed bids received 

for any tract, regardless of the amount 

offered. 

(3) In the event the highest bids are tie 

bids when using sealed bidding 

procedures, the tied bidders may be 

permitted to submit oral bids to 

determine the highest cash bonus 

bidder. 

(c)(1) When the leasing notice 

specifies the use of oral bids, oral bids 

shall be received at the place, time, and 

date and in accordance with the 

procedures specified in the leasing 

notice. 

(2) The Secretary reserves the right to 

reject all oral bids received for any tract, 

regardless of the amount offered. 

(d) When the leasing notice specifies 

the use of deferred cash bonus bidding, 

bids shall be received in accordance 

with paragraph (b) or (c) of this section, 

as appropriate. The high bid will be 

determined based upon the net present 

value of each total bid. The appropriate 

discount rate will be specified in the 

leasing notice. High bidders using the 

deferred bonus option shall pay a 

minimum of 20 percent of the cash 

bonus bid prior to lease issuance. At 

least a total of 60 percent of the cash 

bonus bid shall be due on or before the 

5th anniversary of the lease, and 

payment of the remainder of the cash 

bonus bid shall be due on the 10th 

anniversary of the lease. The lessee shall 

submit a bond guaranteeing payment of 

the deferred portion of the bonus, in 

accordance with § 581.33. 

§ 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 

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Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations 64717 

these regulations but which you submit 

for record purposes, you must also pay 

electronically through Pay.gov a 

nonrefundable fee of $50 per lease 

affected, and you must include a copy 

of the Pay.gov confirmation receipt page 

with your document. Such documents 

may be rejected at the discretion of the 

authorized officer. 

(b) An attorney in fact signing on 

behalf of the holder of a lease or 

sublease, shall furnish evidence of 

authority to execute the assignment or 

application for approval and the 

statement required by § 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 

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species and their habitat; any unique or 

special features in the lease area, other 

natural resources of the OCS; and 

hazards to public health, safety, and 

navigation. 

(k) A description of the measures to 

be taken to monitor the impacts of the 

proposed testing activities in 

accordance with § 582.28(c) of this part. 

(l) A detailed description of the cycle 

of all materials including samples and 

wastes, the method for discharge and 

disposal of waste and refuse, and the 

chemical and physical characteristics of 

such waste and refuse. 

(m) A detailed description of practices 

and procedures to effect the 

abandonment of testing activities, e.g., 

abandonment of a pilot mining facility. 

The proposed procedures shall indicate 

the steps to be taken to assure that 

mined areas do not pose a threat to the 

environment and that the seafloor is left 

free of obstructions and structures that 

may present a hazard to other uses or 

users of the OCS such as navigation or 

commercial fishing. 

(n) A description of potential 

environmental impacts of testing 

activities including the following: 

(1) The location of associated port, 

transport, processing, and waste 

disposal facilities and affected 

environment (e.g., maps, land use, and 

layout); 

(2) A description of the nature and 

degree of potential environmental 

impacts of the proposed testing 

activities and the domestic 

socioeconomic effects of construction 

and operation of the proposed testing 

facilities, including waste 

characteristics and toxicity; 

(3) Any proposed mitigation measures 

to avoid or minimize adverse impacts 

on the environment; 

(4) A certificate of consistency with 

the federally approved State coastal 

zone management program, where 

applicable; and 

(5) Alternate sites and technologies 

considered by the lessee and the reasons 

why they were not selected. 

(o) Any other information needed for 

technical evaluation of the planned 

activities and for evaluation of the 

impact of those activities on the human, 

marine, and coastal environments. 

§ 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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64726 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations 

§ 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 and 

mitigating the impacts of commercialscale recovery more effectively. At a 

minimum, the proposed monitoring 

activities shall address specific concerns 

expressed in the lease-sale 

environmental analysis. 

(6) When required, the monitoring 

plan shall specify: 

(i) The sampling techniques and 

procedures to be used to acquire the 

needed data and information; 

(ii) The format to be used in analysis 

and presentation of the data and 

information; 

(iii) The equipment, techniques, and 

procedures to be used in carrying out 

the monitoring program; and 

(iv) The name and qualifications of 

person(s) designated to be responsible 

for carrying out the environmental 

monitoring. 

(d) [Reserved] 

(e) In the event that equipment or 

procedural failure might result in 

significant additional damage to the 

environment, the lessee shall submit a 

Contingency Plan which specifies the 

procedures to be followed to institute 

corrective actions in response to such a 

failure and to minimize adverse impacts 

on the environment. Such procedures 

shall be designed for the site and mining 

activities described in the approved 

Delineation, Testing, or Mining Plan. 

§ 582.29 Reports and records. 

(a) A report of the amount and value 

of each OCS mineral produced from 

each lease shall be made by the payor 

for the lease for each calendar month, 

beginning with the month in which 

approved testing, development, or 

production activities are initiated and 

shall be filed in duplicate with the 

Director on or before the 20th day of the 

succeeding month, unless an extension 

of time for the filing of such report is 

granted by the Director. The report shall 

disclose accurately and in detail all 

operations conducted during each 

month and present a general summary 

of the status of leasehold activities. The 

report shall be submitted each month 

until the lease is terminated or 

relinquished unless the Director 

authorizes omission of the report during 

an approved suspension of production. 

The report shall show for each calendar 

month the location of each mining and 

processing activity; the number of days 

operations were conducted; the identity, 

quantity, quality, and value of each OCS 

mineral produced, sold, transferred, 

used or otherwise disposed of; identity, 

quantity, and quality of an inventory 

maintained prior to the point of royalty 

determination; and other information as 

may be required by the Director. 

(b) The lessee shall submit a status 

report on exploration and/or testing 

activities under an approved 

Delineation or Testing Plan to the 

Director within 30 days of the close of 

each calendar quarter which shall 

include: 

(1) A summary of activities 

conducted; 

(2) A listing of all geophysical and 

geochemical data acquired and 

developed such as acoustic or seismic 

profiling records; 

(3) A map showing location of holes 

drilled and where bottom samples were 

taken; and 

(4) Identification of samples analyzed. 

(c) Each lessee shall submit to the 

Director a report of exploration and/or 

testing activities within 3 months after 

the completion of operations. The final 

report of exploration and/or testing 

activities conducted on the lease shall 

include: 

(1) A description of work performed; 

(2) Charts, maps, or plats depicting 

the area and leases in which activities 

were conducted specifically identifying 

the lines of geophysical traverses and/or 

the locations where geological activity 

was conducted and/or the locations of 

other exploration and testing activities; 

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(3) The dates on which the actual 

operations were performed; 

(4) A narrative summary of any 

mineral occurrences; environmental 

hazards; and effects of the activities on 

the environment, aquatic life, 

archaeological resources, or other uses 

and users of the area in which the 

activities were conducted; 

(5) Such other descriptions of the 

activities conducted as may be specified 

by the Director; and 

(6) Records of all samples from core 

drilling or other tests made on the lease. 

The records shall be in such form that 

the location and direction of the 

samples can be accurately located on a 

map. The records shall include logs of 

all strata penetrated and conditions 

encountered, such as minerals, water, 

gas, or unusual conditions, and copies 

of analyses of all samples analyzed. 

(d) The lessee shall report the results 

of environmental monitoring activities 

required in § 582.28 of this part and 

shall submit such other environmental 

data as the Director may require to 

conform with the requirements of these 

regulations. 

(e)(1) All maps shall be appropriately 

marked with reference to official lease 

boundaries and elevations marked with 

reference to sea level. When required by 

the Director, vertical projections and 

cross sections shall accompany plan 

views. The maps shall be kept current 

and submitted to the Director annually, 

or more often when required by the 

Director. The accuracy of maps 

furnished shall be certified by a 

professional engineer or land surveyor. 

(2) The lessee shall prepare such 

maps of the leased lands as are 

necessary to show the geological 

conditions as determined from G&G 

surveys, bottom sampling, drill holes, 

trenching, dredging, or mining. All 

excavations shall be shown in such 

manner that the volume of OCS 

minerals produced during a royalty 

period can be accurately ascertained. 

(f) Any lessee who acquires rock, 

mineral, and core samples under a lease 

shall keep a representative split of each 

geological sample and a quarter 

longitudinal segment of each core for 5 

years during which time the samples 

shall be available for inspection at the 

convenience of the Director who may 

take cuts of such cores, cuttings, and 

samples. 

(g)(1) The lessee shall keep all original 

data and information available for 

inspection or duplication, by the 

Director at the expense of the lessor, as 

long as the lease continues in force. 

Should the lessee choose to dispose of 

original data and information once the 

lease has expired, said data and 

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 

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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 issuance 

and administration of leases, right-ofway (ROW) grants, and right-of-use and 

easement (RUE) grants for renewable 

energy production on the Outer 

Continental Shelf (OCS) and RUEs for 

the alternate use of OCS facilities for 

energy or marine-related purposes; 

(b) Inform you and third parties of 

your obligations when you undertake 

activities authorized in this part; and 

(c) Ensure that renewable energy 

activities on the OCS and activities 

involving the alternate use of OCS 

facilities for energy or marine-related 

purposes are conducted in a safe and 

environmentally sound manner, in 

conformance with the requirements of 

subsection 8(p) of the OCS Lands Act, 

other applicable laws and regulations, 

and the terms of your lease, ROW grant, 

RUE grant, or Alternate Use RUE grant. 

(d) This part will not convey access 

rights for oil, gas, or other minerals. 

§ 585.102 What are BOEM’s 

responsibilities under this part? 

(a) BOEM will ensure that any 

activities authorized in this part are 

carried out in a manner that provides 

for: 

(1) Safety; 

(2) Protection of the environment; 

(3) Prevention of waste; 

(4) Conservation of the natural 

resources of the OCS; 

(5) Coordination with relevant Federal 

agencies (including, in particular, those 

agencies involved in planning activities 

that are undertaken to avoid conflicts 

among users and maximize the 

economic and ecological benefits of the 

OCS, including multifaceted spatial 

planning efforts); 

(6) Protection of National security 

interests of the United States; 

(7) Protection of the rights of other 

authorized users of the OCS; 

(8) A fair return to the United States; 

(9) Prevention of interference with 

reasonable uses (as determined by the 

Secretary or Director) of the exclusive 

economic zone, the high seas, and the 

territorial seas; 

(10) Consideration of the location of 

and any schedule relating to a lease or 

grant under this part for an area of the 

OCS, and any other use of the sea or 

seabed; 

(11) Public notice and comment on 

any proposal submitted for a lease or 

grant under this part; and 

(12) Oversight, inspection, research, 

monitoring, and enforcement of 

activities authorized by a lease or grant 

under this part. 

(b) BOEM will require compliance 

with all applicable laws, regulations, 

other requirements, and the terms of 

your lease or grant under this part and 

approved plans. BOEM will approve, 

disapprove, or approve with conditions 

any plans, applications, or other 

documents submitted to BOEM for 

approval under the provisions of this 

part. 

(c) Unless otherwise provided in this 

part, BOEM may give oral directives or 

decisions whenever prior BOEM 

approval is required under this part. 

BOEM will document in writing any 

such oral directives within 10 business 

days. 

(d) BOEM will establish practices and 

procedures to govern the collection of 

all payments due to the Federal 

Government, including any cost 

recovery fees, rents, operating fees, and 

other fees or payments. BOEM will do 

this in accordance with the terms of this 

part, the leasing notice, the lease or 

grant under this part, and applicable 

Office of Natural Resources Revenue 

regulations or guidance. 

(e) BOEM will provide for 

coordination and consultation with the 

Governor of any State or the executive 

of any local government or Indian Tribe 

that may be affected by a lease, 

easement, or ROW under this 

subsection. BOEM may invite any 

affected State Governor, representative 

of an affected Indian Tribe, and affected 

local government executive to join in 

establishing a task force or other joint 

planning or coordination agreement in 

carrying out our responsibilities under 

this part. 

§ 585.103 When may BOEM prescribe or 

approve departures from these regulations? 

(a) BOEM may prescribe or approve 

departures from these regulations when 

departures are necessary to: 

(1) Facilitate the appropriate activities 

on a lease or grant under this part; 

(2) Conserve natural resources; 

(3) Protect life (including human and 

wildlife), property, or the marine, 

coastal, or human environment; or 

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(4) Protect sites, structures, or objects 

of historical or archaeological 

significance. 

(b) Any departure approved under 

this section and its rationale must: 

(1) Be consistent with subsection 8(p) 

of the OCS Lands Act; 

(2) Protect the environment and the 

public health and safety to the same 

degree as if there was no approved 

departure from the regulations; 

(3) Not impair the rights of third 

parties; and 

(4) Be documented in writing. 

§ 585.104 Do I need a BOEM lease or other 

authorization to produce or support the 

production of electricity or other energy 

product from a renewable energy resource 

on the OCS? 

Except as otherwise authorized by 

law, it will be unlawful for any person 

to construct, operate, or maintain any 

facility to produce, transport, or support 

generation of electricity or other energy 

product derived from a renewable 

energy resource on any part of the OCS, 

except under and in accordance with 

the terms of a lease, easement, or ROW 

issued pursuant to the OCS Lands Act. 

§ 585.105 What are my responsibilities 

under this part? 

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-bycase basis? 

(a) BOEM will charge a processing fee 

on a case-by-case basis under the 

procedures in this section with regard to 

any application or request under this 

part if we decide at any time that the 

preparation of a particular document or 

study is necessary for the application or 

request and it will have a unique 

processing cost, such as the preparation 

of an Environmental Assessment (EA) or 

Environmental Impact Statement (EIS). 

(1) Processing costs will include 

contract oversight and efforts to review 

and approve documents prepared by 

contractors, whether the contractor is 

paid directly by the applicant or 

through BOEM. 

(2) We may apply a standard overhead 

rate to direct processing costs. 

(b) We will assess the ongoing 

processing fee for each individual 

application or request according to the 

following procedures: 

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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 

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Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations 64735 

permanently moored vessels. Any group 

of OCS installations interconnected 

with walkways, or any group of 

installations that includes a central or 

primary installation with one or more 

satellite or secondary installations, is a 

single facility. BOEM may decide that 

the complexity of the installations 

justifies their classification as separate 

facilities. 

Geographic center of a project means 

the centroid (geometric center point) of 

a qualified project area. The centroid 

represents the point that is the weighted 

average of coordinates of the same 

dimension within the mapping system, 

with the weights determined by the 

density function of the system. For 

example, in the case of a project area 

shaped as a rectangle or other 

parallelogram, the geographic center 

would be that point where lines 

between opposing corners intersect. The 

geographic center of a project could be 

outside the project area itself if that area 

is irregularly shaped. 

Governor means the Governor of a 

State or the person or entity lawfully 

designated by or under State law to 

exercise the powers granted to a 

Governor. 

Grant means a right-of-way, right-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. 

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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 pertaining to a lease or grant; 

assignment and designation of operator; and suspension, renewal, 

termination, relinquishment, and cancellation of leases and grants. 

(5) Subpart E—Payments and Financial 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 installation 

of facilities on a lease or grant to ensure that these facilities are designed, fabricated, and installed according to appropriate standards 

in compliance with BOEM regulations, and where applicable, the approved plan. 

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Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations 64737 

30 CFR 585 subpart, title, and/or BOEM Form (OMB Control No.) Reasons for collecting information and how used 

(8) Subpart H—Environmental and Safety Management, Inspections, 

and Facility Assessments.

To ensure that lease and grant operations are conducted in a manner 

that is safe and protects the environment. To ensure compliance with 

other Federal laws, these regulations, the lease or grant, and approved plans. 

(9) Subpart I—Decommissioning ............................................................. To determine that decommissioning activities comply with regulatory 

requirements and approvals. To ensure that site clearance and platform or pipeline removal are properly performed to protect marine life 

and the environment and do not conflict with other users of the OCS. 

(10) Subpart J—RUEs for Energy and 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. 

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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 

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hazards); archaeological sites on the 

seabed or nearshore; multiple uses of 

the proposed leasing area (including 

navigation, recreation, and fisheries); 

and other socioeconomic, biological, 

and environmental information; and 

(3) Suggest areas to be considered by 

the respondents for leasing. 

(b) Area Identification. BOEM will 

identify areas for environmental 

analysis and consideration for leasing. 

We will do this in consultation with 

appropriate Federal agencies, States, 

local governments, affected Indian 

Tribes, and other interested parties. 

(1) We may consider for lease those 

areas nominated in response to the Call 

for Information and Nominations, 

together with other areas that BOEM 

determines are appropriate for leasing. 

(2) We will evaluate the potential 

effect of leasing on the human, marine, 

and coastal environments, and develop 

measures to mitigate adverse impacts, 

including lease stipulations. 

(3) We will consult to develop 

measures, including lease stipulations 

and conditions, to mitigate adverse 

impacts on the environment; and 

(4) We may hold public hearings on 

the environmental analysis after 

appropriate notice. 

(c) Proposed Sale Notice. BOEM will 

publish the Proposed Sale Notice in the 

Federal Register and send it to the 

Governor of any affected State and the 

executive of any local government that 

might be affected. The comment period 

following issuance of a Proposed Sale 

Notice will be 60 days. 

(d) Final Sale Notice. BOEM will 

publish the Final Sale Notice in the 

Federal Register at least 30 days before 

the date of the sale. 

§ 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: 

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Type of auction Bid variable Bidding process 

(1) Sealed bidding .............................................. A cash bonus or an operating fee rate ............ One sealed bid per 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 to set the operating fee for 

the first year of the operations term of your lease. The fee rate for 

subsequent years changes by a mathematical function we specify in 

the Final Sale Notice. 

(4) Cash bonus and constant operating 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 limited 

to, 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; 

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(2) File financial assurance as 

required under §§ 585.515 through 

585.537; and 

(3) Pay the balance of the bonus bid 

as specified in the lease sale notice. 

(b) Within 45 days after you receive 

the lease copies, you must pay the first 

6 months rent as required in § 585.503. 

(c) When you execute three copies of 

the lease and return the copies to us, we 

will execute the lease on behalf of the 

United States and send you one fully 

executed copy. 

(d) You will forfeit your deposit if you 

do not execute and return the lease 

within 10 business days of receipt, or 

otherwise fail to comply with applicable 

regulations or terms of the Final Sale 

Notice. 

(e) We may extend the 10 business 

day time period for executing and 

returning the lease if we determine the 

delay to be caused by events beyond 

your control. 

(f) We reserve the right to withdraw 

an OCS area in which we have held a 

lease sale before you and BOEM execute 

the lease in that area. If we exercise this 

right, we will refund your bid deposit, 

without interest. 

(g) If the awarded lease is executed by 

an agent acting on behalf of the bidder, 

the bidder must submit, along with the 

executed lease, written evidence that 

the agent is authorized to act on behalf 

of the bidder. 

(h) BOEM will consider the highest 

submitted qualified bid to be the 

winning bid when bidding occurs under 

the systems described in § 585.221(a)(1) 

through (5). We will determine the 

winning bid for proposals submitted 

under the multiple-factor bidding 

format on the basis of selection by the 

panel as specified in § 585.222(d) when 

the bidding system under 

§ 585.221(a)(6) is used. We will refund 

the deposit on all other bids. 

§ 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 

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extensions are as shown in the 

following table: 

Lease term Automatic extensions Requirements 

(1) Each commercial lease issued competitively 

will have a preliminary term of 6 months to 

submit: 

(i) a SAP; or 

(ii) a combined SAP and COP. The preliminary term begins on the effective date of 

the lease. A commercial lease issued 

noncompetitively does not have a preliminary term. 

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 site 

assessment 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 the 

SAP/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 a 

GAP. The preliminary term begins on the effective date of the lease. 

If we receive a GAP that satisfies the requirements of §§ 585.640 through 585.648 of 

this part, the preliminary term will be automatically extended for the period of time 

necessary for us to conduct a technical and 

environmental review of the plans.

The GAP must meet the requirements of 

§§ 585.640 through 585.648. 

(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. 

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§ 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 

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period you are prohibited from 

conducting activities. 

(d) You must continue to make all 

required payments on your lease or 

grant during the period a cessation order 

is in effect. 

§ 585.403 [Reserved] 

§ 585.404 [Reserved] 

Designation of Operator 

§ 585.405 How do I designate an operator? 

(a) If you intend to designate an 

operator who is not the lessee or grant 

holder, you must identify the proposed 

operator in your SAP (under 

§ 585.610(a)(3)), COP (under 

§ 585.626(b)(2)), or GAP (under 

§ 585.645(b)(3)), as applicable. If no 

operator is designated in a SAP, COP, or 

GAP, BOEM will deem the lessee or 

grant holder to be the operator. 

(b) An operator must be designated in 

any SAP, COP, or GAP if there is more 

than one lessee or grant holder for any 

individual lease or grant. 

(c) Once approved in your plan, the 

designated operator is authorized to act 

on your behalf and required to perform 

activities necessary to comply with the 

OCS Lands Act, the lease or grant, and 

the regulations in this part. 

(d) You, or your designated operator, 

must immediately provide BOEM with 

a written notification of change of 

address of the lessee or operator. 

(e) If there is a change in the 

designated operator, you must provide 

written notice to BOEM and identify the 

new designated operator within 72 

hours on a form approved by BOEM. 

The lessee(s) or grantee(s) is the 

operator and responsible for compliance 

until BOEM approves designation of the 

new operator. 

(f) Designation of an operator under 

any lease or grant issued under this part 

does not relieve the lessee or grant 

holder of its obligations under this part 

or its lease or grant. 

(g) A designated operator performing 

activities on the lease must comply with 

all regulations governing those activities 

and may be held liable or penalized for 

any noncompliance during the time it 

was operator, notwithstanding its 

subsequent resignation. 

§ 585.406 Who is responsible for fulfilling 

lease and grant obligations? 

(a) When you are not the sole lessee 

or grantee, you and your co-lessee(s) or 

co-grantee(s) are jointly and severally 

responsible for fulfilling your 

obligations under the lease or grant and 

the provisions of this part, unless 

otherwise provided in these regulations. 

(b) If your designated operator fails to 

fulfill any of your obligations under the 

lease or grant and this part, BOEM may 

require you or any or all of your 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; 

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(3) Required by National security or 

defense; or 

(4) The Secretary determines after 

notice and opportunity for a hearing 

that continued activity under the lease 

or grant: 

(i) Would cause serious harm or 

damage to natural resources; life 

(including human and wildlife); 

property; the marine, coastal, or human 

environment; or sites, structures, or 

objects of historical or archaeological 

significance; and 

(ii) That the threat of harm or damage 

would not disappear or decrease to an 

acceptable extent within a reasonable 

period of time; and 

(iii) The advantages of cancellation 

outweigh the advantages of continuing 

the lease or grant in force. 

Subpart E—Payments and Financial 

Assurance Requirements 

Payments 

§ 585.500 How do I make payments under 

this part? 

(a) For acquisition fees or the initial 

6-months rent paid for the preliminary 

term of your lease, you must make 

credit card or automated clearing house 

payments through the Pay.gov Web site, 

and you must include one copy of the 

Pay.gov confirmation receipt page with 

your unsolicited request or signed lease 

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 

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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 

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available wholesale power price indices; 

and 

(ii) May adjust the published average 

wholesale power price to reflect 

documented variations by State or 

within a region and recent market 

conditions. 

(3) BOEM will select the capacity 

factor ‘‘c’’ based upon applicable 

analogs drawn from present and future 

domestic and foreign projects that 

operate in comparable conditions and 

on comparable scales. 

(i) Upon the completion of the first 

year of commercial operations on the 

lease, BOEM may adjust the capacity 

factor as necessary (to accurately 

represent a comparison of actual 

production over a given period of time 

with the amount of power a facility 

would have produced if it had run at 

full capacity) in a subsequent year. 

(ii) After the first adjustment, BOEM 

may adjust the capacity factor (to 

accurately represent a comparison of 

actual generation over a given period of 

time with the amount of power a facility 

would have generated if it had run at 

full capacity) no earlier than in 5-year 

intervals from the most recent year that 

BOEM adjusts the capacity factor. 

(iii) The process by which BOEM will 

adjust the capacity factor, including any 

calculations (incorporating an average 

capacity factor reflecting actual 

operating experience), will be specified 

in the lease. The operator or lessee may 

request review and adjustment of the 

capacity factor under § 585.510. 

(4) Ten days after the anniversary date 

of when you began to commercially 

generate electricity, you must submit to 

BOEM documentation of the gross 

annual generation of electricity 

produced by the generating facility on 

the lease. You must use the same 

information collection form as 

authorized by the EIA for this 

information. 

(5) For the nameplate capacity ‘‘M,’’ 

BOEM will use the total installed 

capacity of the equipment you install, as 

specified in your approved COP. 

(d) You must submit all operating fee 

payments to BOEM in accordance with 

the provisions under 30 CFR 1218.51. 

(e) BOEM will establish the operating 

fee in the Final Sale Notice or in the 

lease on a case-by-case basis for: 

(1) Activities that do not relate to the 

generation of electricity (e.g., hydrogen 

production), and 

(2) Leases issued for hydrokinetic 

activities requiring a FERC license. 

§ 585.507 What rent payments must I pay 

on a project easement? 

(a) You must pay ONRR, under the 

regulations at 30 CFR part 1218, a rent 

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 

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performance up to $100,000, as 

specified in §§ 585.526 through 585.529. 

(b) You meet the financial assurance 

requirements under this subpart if your 

designated lease operator provides a 

$100,000 minimum, lease-specific bond 

or other approved financial assurance 

that guarantees compliance with all 

terms and conditions of the lease. 

(1) The dollar amount of the 

minimum, lease-specific financial 

assurance in paragraphs (a)(1) and (b) of 

this section will be adjusted to reflect 

changes in the Consumer Price IndexAll Urban Consumers (CPI–U) or a 

substantially equivalent index if the 

CPI–U is discontinued; and 

(2) The first CPI–U-based adjustment 

can be made no earlier than the 5-year 

anniversary of the adoption of this rule. 

Subsequent CPI–U-based adjustments 

may be made every 5 years thereafter. 

§ 585.516 What are the financial assurance 

requirements for each stage of my 

commercial lease? 

(a) The basic financial assurance 

requirements for each stage of your 

commercial lease are as follows: 

Before BOEM will . . . You must provide . . . 

(1) Issue a commercial lease or approve an assignment of an existing 

commercial lease.

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 that 

a supplemental bond is required in addition to your minimum leasespecific bond, due to the complexity, number, and location of any facilities involved in your site assessment activities. 

(3) Approve your COP .............................................................................. A supplemental bond or other financial assurance, in an amount determined by BOEM based on the complexity, number, and location of 

all facilities involved in your planned activities and commercial operation. The supplemental financial assurance requirement is in addition to your lease-specific bond and, if applicable, the previous supplement associated with SAP approval. 

(4) Allow you to install facilities 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 operator 

provides a minimum limited leasespecific or grant-specific bond in an 

amount sufficient to guarantee 

compliance with all terms and 

conditions of the limited lease or grant. 

(1) The dollar amount of the 

minimum, lease- or grant-specific 

financial assurance in paragraph (a)(1) 

of this section will be adjusted to reflect 

changes in the CPI–U or a substantially 

equivalent index if the CPI–U is 

discontinued; and 

(2) The first CPI–U-based adjustment 

can be made no earlier than the 5-year 

anniversary of the adoption of this rule. 

Subsequent CPI–U-based adjustments 

may be made every 5 years thereafter. 

§ 585.521 Do my financial assurance 

requirements change as activities progress 

on my limited lease or grant? 

(a) BOEM may require you to increase 

the level of your financial assurance as 

activities progress on your limited lease 

or grant. We will base the determination 

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for the amount of financial assurance 

requirements on our estimate of the cost 

to meet all accrued lease or grant 

obligations, including: 

(1) The projected amount of rent and 

other payments due the Government 

over the next 12 months; 

(2) Any past due rent and other 

payments; 

(3) Other monetary obligations; and 

(4) The estimated cost of facility 

decommissioning. 

(b) You may satisfy the requirement 

for increased financial assurance levels 

for the limited lease or grant by 

increasing the amount of your existing 

bond or replacing your existing bond. 

(c) BOEM will authorize you to 

establish a separate decommissioning 

bond or other financial assurance for 

your limited lease or grant. 

(1) The separate decommissioning 

bond or other financial assurance 

instrument must meet the requirements 

specified in §§ 585.525 through 585.529. 

(2) BOEM will allow you to provide 

your financial assurance for 

decommissioning in accordance with 

the number of facilities installed or 

being installed. BOEM must approve the 

schedule for providing the appropriate 

financial assurance coverage. 

§§ 585.522–585.524 [Reserved] 

Requirements for Financial Assurance 

Instruments 

§ 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 

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ratings or trade references, including 

names and addresses of other lessees, 

contractors, and suppliers with whom 

you have dealt; and 

(4) Evidence that shows a record of 

compliance with laws, regulations, and 

lease, ROW, or RUE terms. 

(b) If we approve your request to use 

your financial strength and reliability to 

meet your financial assurance 

requirements, you must submit annual 

updates to the information required by 

paragraph (a) of this section. You must 

submit this information no later than 

March 31 of each year. 

(c) If the annual updates to the 

information required by paragraph (a) of 

this section do not continue to 

demonstrate financial strength and 

reliability or BOEM has reason to 

believe that you are unable to meet the 

financial assurance requirements of this 

section, after notice and opportunity for 

a hearing, BOEM will terminate your 

ability to use financial strength and 

reliability for financial assurance and 

require you to provide another type of 

financial assurance. You must provide 

this new financial assurance instrument 

within 90 days after we terminate your 

use of financial strength and reliability. 

§ 585.528 May I use a third-party guaranty 

to meet the financial assurance requirement 

for lease or grant activities? 

(a) You may use a third-party 

guaranty if the guarantor meets the 

criteria prescribed in paragraph (b) of 

this section and submits an agreement 

meeting the criteria prescribed in 

paragraph (c) of this section. The 

agreement must guarantee compliance 

with the obligations of all lessees and 

operators and grant holders. 

(b) BOEM will consider the following 

factors in deciding whether to accept an 

agreement: 

(1) The length of time that your 

guarantor has been in continuous 

operation as a business entity. You may 

exclude periods of interruption that are 

beyond the guarantor’s control by 

demonstrating, to the satisfaction of the 

Director, that the interruptions do not 

affect the likelihood of your guarantor 

remaining in business during the SAP, 

COP, and decommissioning stages of 

activities covered by the indemnity 

agreement. 

(2) Financial information available in 

the public record or submitted by your 

guarantor in sufficient detail to show us 

that your guarantor meets the criterion 

stated in paragraph (b)(4) of this section. 

Such detail includes: 

(i) The current rating for your 

guarantor’s most recent bond issuance 

by a generally recognized bond rating 

service such as Moody’s Investor 

Service or Standard and Poor’s 

Corporation; 

(ii) Your guarantor’s net worth, taking 

into account liabilities for compliance 

with all terms and conditions of your 

lease, regulations, and other guarantees; 

(iii) Your guarantor’s ratio of current 

assets to current liabilities, taking into 

account liabilities for compliance with 

all terms and conditions of your lease, 

regulations, and other guarantees; and 

(iv) Your guarantor’s unencumbered 

domestic fixed assets. 

(3) If the information in paragraph 

(b)(2) of this section is not publicly 

available, your guarantor must submit 

the information in the following table, 

to be updated annually within 90 days 

of the end of the fiscal year (FY) or as 

otherwise prescribed. 

Your guarantor must submit . . . That . . . 

(i) Financial statements for the most recently completed FY .................. Include a report by an independent certified public accountant containing the accountant’s audit or review opinion of the statements. 

The report must be prepared in conformance with generally accepted 

accounting principles and contain no adverse opinion. 

(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 grantspecific decommissioning account to meet 

the financial assurance requirements 

related to decommissioning? 

(a) In lieu of a surety bond, BOEM 

may authorize you to establish a 

lease-, ROW grant-, or RUE grantspecific decommissioning account in a 

federally-insured institution. The funds 

may not be withdrawn from the account 

without our written approval. 

(1) The funds must be payable to 

BOEM and pledged to meet your lease 

or grant decommissioning and site 

clearance obligations; and 

(2) You must fully fund the account 

within the time BOEM prescribes to 

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cover all costs of decommissioning 

including site clearance. BOEM will 

estimate the cost of decommissioning, 

including site clearance. 

(b) Any interest paid on the account 

will be treated as account funds unless 

we authorize in writing that any interest 

be paid to the depositor. 

(c) We may allow you to pledge 

Treasury securities, payable to BOEM 

on demand, to satisfy your obligation to 

make payments into the account. 

Acceptable Treasury securities and their 

collateral value are determined in 

accordance with 31 CFR part 203, 

Collateral Margins Table (which can be 

found at 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 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. 

(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 of 

the 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 Si is equal to the nearest 

distance from the geographic center of 

the project area to the i = 1, 2, * * * nth 

eligible State’s coastline, then eligible 

State i would be entitled to the fraction 

Fi of the 27-percent aggregate revenue 

share due to all the eligible States 

according to the formula: 

Fi= (1/Si) ÷ (Si=1* * *n(1/Si)). 

§ 585.541 What is a qualified project for 

revenue sharing purposes? 

A qualified project for the purpose of 

revenue sharing with eligible coastal 

States is one authorized under 

subsection 8(p) of the OCS Lands Act, 

which includes acreage within the area 

extending 3 nautical miles seaward of 

State submerged lands. A qualified 

project is subject to revenue sharing 

with those States that are eligible for 

revenue sharing under § 585.542. The 

entire area within a lease or grant for the 

qualified project, excluding project 

easements, is considered the qualified 

project area. 

§ 585.542 What makes a State eligible for 

payment of revenues? 

A State is eligible for payment of 

revenues if any part of the State’s 

coastline is located within 15 miles of 

the announced geographic center of the 

project area of a qualified project. A 

State is not eligible for revenue sharing 

if all parts of that State’s coastline are 

more than 15 miles from the announced 

geographic center of the qualified 

project area. This is the case even if the 

qualified project area is located wholly 

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or partially within an area extending 3 

nautical miles seaward of the 

submerged lands of that State or if there 

are no States with a coastline less than 

15 miles from the announced 

geographic center of the qualified 

project area. 

§ 585.543 Example of how the inverse 

distance formula works. 

(a) Assume that the geographic center 

of the project area lies 12 miles from the 

closest coastline point of State A and 4 

miles from the closest coastline point of 

State B. BOEM will round dollar shares 

to the nearest whole dollar. The 

proportional share due each State would 

be calculated as follows: 

(1) State A’s share = [(1⁄12) ÷ (1⁄12+1⁄4)] 

= 1⁄4. 

(2) State B’s share = [(1⁄4) ÷ (1⁄12+1⁄4)] 

= 3⁄4. 

(b) Therefore, State B would receive a 

share of revenues that is three times as 

large as that awarded to State A, based 

on the finding that State B’s nearest 

coastline is one-third the distance to the 

geographic center of the qualified 

project area as compared to State A’s 

nearest coastline. Eligible States share 

the 27 percent of the total revenues from 

the qualified project as mandated under 

the OCS Lands Act. Hence, if the 

qualified project generates $1,000,000 of 

Federal revenues in a given year, the 

Federal Government would distribute 

the States’ 27-percent share as follows: 

(1) State A’s share = $270,000 × 1⁄4 = 

$67,500. 

(2) State B’s share = $270,000 × 3⁄4 = 

$202,500. 

Subpart F—Plans and Information 

Requirements 

§ 585.600 What plans and information 

must I submit to BOEM before I conduct 

activities on my lease or grant? 

You must submit a SAP, COP, or GAP 

and receive BOEM approval as set forth 

in the following table: 

Before you: you must: 

(a) conduct any site assessment activities on your commercial lease, submit and obtain approval for your SAP according to §§ 585.605 

through 585.613. 

(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 and 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 conduct 

activities on your lease, and how you will mitigate environmental impacts from your proposed activities, including a description of the 

measures you will use as required by subpart H of this part. 

(9) CVA nomination, if required ................................................................ CVA nominations for reports in subpart G of this part, as required by 

§ 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 your 

SAP 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 underlying 

conditions will not influence the integrity or performance of the structure. This could include a series of 

sampling locations (borings and in situ tests) as well 

as laboratory testing of soil samples, but may consist 

of a minimum of one deep boring with samples. 

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Information Report contents Including 

(2) Shallow hazards ............. The results from the shallow hazards survey with supporting data.A description of information sufficient to determine the 

presence of the following features and their likely effects on your proposed facility, including: 

(i) Shallow faults; 

(ii) Gas seeps or shallow gas; 

(ii) Slump blocks or slump sediments; 

(iv) Hydrates; and 

(v) Ice scour of seabed sediments. 

(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 of 

other marine resources such as fish populations (including migratory populations), marine mammals, sea 

turtles, and sea birds. 

(c) If you submit your COP or FERC 

license application with your SAP then: 

(1) You must provide sufficient data 

and information with your COP or FERC 

license application for BOEM and/or 

FERC to complete the needed reviews 

and NEPA analysis. 

(2) You may need to revise your COP 

or FERC license application and BOEM 

and/or FERC may need to conduct 

additional reviews, including NEPA 

analysis, if new information becomes 

available after you complete your site 

assessment activities. 

§ 585.611 What information must I submit 

with my SAP to assist BOEM in complying 

with NEPA and other relevant laws? 

(a) You must submit with your SAP 

detailed information to assist BOEM in 

complying with NEPA and other 

relevant laws, as appropriate. For a 

noncompetitive commercial lease, you 

must submit a SAP that describes those 

resources, conditions, and activities 

listed in the following table that could 

be affected by your proposed activities, 

or that could affect the activities 

proposed in your SAP. 

(b) For competitively issued 

commercial leases, BOEM will have 

prepared a NEPA document and 

consistency determination for the lease 

sale and site assessment activities. 

However, if you submit a SAP that 

shows changes in impacts from those 

identified in the NEPA document or 

consistency determination prepared for 

the lease, BOEM may determine that 

your SAP is subject to a new NEPA/ 

CZMA and other relevant Federal 

reviews. In that case, BOEM will notify 

you of the determination, and you must 

submit a SAP that describes those 

resources, conditions, and activities 

listed in the following table that could 

be affected by your proposed activities, 

or that could affect the activities 

proposed in your SAP, including: 

Type of information Including 

(1) Hazard information .............................................................................. Meteorology, oceanography, sediment transport, geology, and shallow 

geological or manmade hazards. 

(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 appropriate: 

(i) 15 CFR part 930, subpart D, for noncompetitive leases; 

(ii) 15 CFR part 930, subpart E, for competitive leases. 

(10) Other resources, conditions, and 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 those 

identified in the lease sale consistency determination, you may be subject to a new consistency review. In that case, BOEM will notify you of the determination and we will forward to 

the State CZM agency 1 copy and 1 electronic copy of your SAP, consistency certification, 

and necessary data and information required under 15 CFR part 930, subpart E, after 

BOEM has determined that all information requirements for the SAP are met and BOEM 

prepares its NEPA compliance document. 

(b) Noncompetitively ........................................... You will furnish a copy of your SAP, consistency certification, and necessary data and information pursuant to 15 CFR part 930, subpart D, to the State’s CZM agency and BOEM at 

the same time. 

§ 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 the 

following features and their likely effects on your proposed facility, including: 

(i) Shallow faults; 

(ii) Gas seeps or shallow gas; 

(iii) Slump blocks or slump sediments; 

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Information: Report contents: 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 of biological surveys used 

to determine the presence of live bottoms, hard bottoms, and topographic features, and surveys of other 

marine resources such as fish populations (including 

migratory populations), marine mammals, sea turtles, 

and sea birds. 

(4) Geotechnical survey ....... The results of your sediment testing program with supporting data, the various field and laboratory test 

methods employed, and the applicability of these 

methods as they pertain to the quality of the samples, the type of sediment, and the anticipated design 

application. You must explain how the engineering 

properties of each sediment stratum affect the design 

of your facility. In your explanation, you must describe the uncertainties inherent in your overall testing program, and the reliability and applicability of 

each test method.

(i) The results of a testing program used to investigate 

the stratigraphic and engineering properties of the 

sediment that may affect the foundations or anchoring systems for your facility. 

(ii) The results of adequate in situ testing, boring, and 

sampling at each foundation location, to examine all 

important sediment and rock strata to determine its 

strength classification, deformation properties, and 

dynamic characteristics. 

(iii) The results of a minimum of one deep boring (with 

soil sampling and testing) at each edge of the project 

area and within the project area as needed to determine the vertical and lateral variation in seabed conditions and to provide the relevant geotechnical data 

required for design. 

(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 that 

integrates 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, description 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 and water depth for all proposed and existing 

structures, facilities, and appurtenances located both offshore and 

onshore, including all anchor/mooring data. 

(6) General structural and project design, fabrication, and installation ... Information for each type of structure associated with your project and, 

unless BOEM provides otherwise, how you will use a CVA to review 

and verify each stage of the project. 

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Project information: Including: 

(7) All cables and pipelines, including cables on project easements ...... Location, design and installation methods, testing, maintenance, repair, 

safety devices, exterior corrosion protection, inspections, and decommissioning. 

(8) A description of the deployment activities .......................................... Safety, prevention, and environmental protection 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 conduct 

activities on your lease, and how you will mitigate environmental impacts from your proposed activities, including a description of the 

measures you will use as required by subpart H of this part. 

(16) Information you incorporate by 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 underlying 

conditions will not influence the integrity or performance of the structure. This could include a series of 

sampling locations (borings and in situ tests) as well 

as laboratory testing of soil samples, but may consist 

of a minimum of one deep boring with samples. 

(2) Shallow hazards ............. The results from the shallow hazards survey with supporting data.A description of information sufficient to determine the 

presence of the following features and their likely effects on your proposed facility, including: 

(i) Shallow faults; 

(ii) Gas seeps or shallow gas; 

(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 and 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 your 

GAP 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, description 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, maintenance, repair, 

safety devices, exterior corrosion protection, inspections, and decommissioning. 

(3) A description of the deployment activities .......................................... Safety, prevention, and environmental protection 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 implementing regulations as promulgated by the 

EPA under 40 CFR part 55. 

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(b) For air quality modeling that you 

perform in support of the activities 

proposed in your plan, you should 

contact the appropriate regulatory 

agency to establish a modeling protocol 

to ensure that the agency’s needs are 

met and that the meteorological files 

used are acceptable before initiating the 

modeling work. In the western Gulf of 

Mexico (west of 87.5° west longitude), 

you must submit to BOEM three copies 

of the modeling report and three sets of 

digital files as supporting information. 

The digital files must contain the 

formatted meteorological files used in 

the modeling runs, the model input file, 

and the model output file. 

Subpart G—Facility Design, 

Fabrication, and Installation 

Reports 

§ 585.700 What reports must I submit to 

BOEM before installing facilities described 

in my approved SAP, COP, or GAP? 

(a) You must submit the following 

reports to BOEM before installing 

facilities described in your approved 

COP (§ 585.632(a)) and, when required 

by this part, your SAP (§ 585.614(b)) or 

GAP (§ 585.651): 

(1) A Facility Design Report; and 

(2) A Fabrication and Installation 

Report. 

(b) You may begin to fabricate and 

install the approved facilities after 

BOEM notifies you that it has received 

your reports and has no objections. If 

BOEM receives the reports, but does not 

respond with objections within 60 days 

of receipt or 60 days after we approve 

your SAP, COP, or GAP, if you 

submitted your report with the plan, 

BOEM is deemed not to have objections 

to the reports, and you may commence 

fabrication and installation of your 

facility or facilities. 

(c) If BOEM has any objections, we 

will notify you verbally or in writing 

within 60 days of receipt of the report. 

Following initial notification of 

objections, BOEM may follow up with 

written correspondence outlining its 

specific objections to the report and 

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 in 

the design or analysis of the facility. Examples of relevant data include information on: 

(i) Extreme weather; 

(ii) Seafloor conditions; and 

(iii) Waves, wind, current, tides, temperature, snow and ice effects, marine 

growth, and water depth. 

You must submit 1 paper copy and 1 electronic copy. 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 submit 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 .............................. You must submit 1 paper copy and 1 electronic copy. 

(3) Fabrication information ................................. The industry standards you will use to ensure 

the 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, including 

onshore 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 as 

appropriate. The certified design and asbuilt plans and specifications will be on 

file at (given location).’’ 

(d) BOEM will withhold trade secrets 

and commercial or financial information 

that is privileged or confidential from 

public disclosure under exemption 4 of 

the FOIA and in accordance with the 

terms of § 585.113. 

§ 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 

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interest, or the appearance of a conflict 

of interest. 

(d) The verification must be 

conducted by or under the direct 

supervision of registered professional 

engineers. 

(e) BOEM will approve or disapprove 

your CVA as part of its review of the 

COP or, when required, of your SAP or 

GAP. 

(f) You must nominate a new CVA for 

BOEM approval if the previously 

approved CVA: 

(1) Is no longer able to serve in a CVA 

capacity for the project; or 

(2) No longer meets the requirements 

for a CVA set forth in this subpart. 

§ 585.707 What are the CVA’s primary 

duties for facility design review? 

If you are required to use a CVA: 

(a) The CVA must use good 

engineering judgment and practices in 

conducting an independent assessment 

of the design of the facility. The CVA 

must certify in the Facility Design 

Report to BOEM that the facility is 

designed to withstand the 

environmental and functional load 

conditions appropriate for the intended 

service life at the proposed location. 

(b) The CVA must conduct an 

independent assessment of all proposed: 

(1) Planning criteria; 

(2) Operational requirements; 

(3) Environmental loading data; 

(4) Load determinations; 

(5) Stress analyses; 

(6) Material designations; 

(7) Soil and foundation conditions; 

(8) Safety factors; and 

(9) Other pertinent parameters of the 

proposed design. 

(c) For any floating facility, the CVA 

must ensure that any requirements of 

the U.S. Coast Guard for structural 

integrity and stability (e.g., verification 

of center of gravity), have been met. The 

CVA must also consider: 

(1) Foundations, foundation pilings 

and templates, and anchoring systems; 

and 

(2) Mooring or tethering systems. 

§ 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 overall 

structure, including any turrets, turretand-hull interfaces, any mooring line 

and chain and riser tensioning line 

segments; and 

(14) Status of quality-control records 

at various stages of fabrication. 

(b) For any floating facilities, the CVA 

or project engineer must ensure that any 

requirements of the U.S. Coast Guard for 

structural integrity and stability (e.g., 

verification of center of gravity) have 

been met. The CVA or project engineer 

must also consider: 

(1) Foundations, foundation pilings 

and templates, and anchoring systems; 

and 

(2) Mooring or tethering systems. 

§ 585.710 When conducting onsite 

installation inspections, what must the CVA 

or project engineer do? 

To comply with § 585.708(a)(4), the 

CVA or project engineer must make 

periodic onsite inspections while 

installation is in progress and must, as 

appropriate, verify, witness, survey, or 

check, the installation items required by 

this section. 

(a) The CVA or project engineer must 

verify, as appropriate, all of the 

following: 

(1) Loadout and initial flotation 

procedures; 

(2) Towing operation procedures to 

the specified location, and review the 

towing records; 

(3) Launching and uprighting 

activities; 

(4) Submergence activities; 

(5) Pile or anchor installations; 

(6) Installation of mooring and 

tethering systems; 

(7) Final deck and component 

installations; and 

(8) Installation at the approved 

location according to the Facility Design 

Report and the Fabrication and 

Installation Report. 

(b) For a fixed or floating facility, the 

CVA or project engineer must verify that 

proper procedures were used during the 

following: 

(1) The loadout of the jacket, decks, 

piles, or structures from each fabrication 

site; and 

(2) The actual installation of the 

facility or major modification and the 

related installation activities. 

(c) For a floating facility, the CVA or 

project engineer must verify that proper 

procedures were used during the 

following: 

(1) The loadout of the facility; 

(2) The installation of foundation 

pilings and templates, and anchoring 

systems; and 

(3) The installation of the mooring 

and tethering systems. 

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(d) The CVA or project engineer must 

conduct an onsite survey of the facility 

after transportation to the approved 

location. 

(e) The CVA or project engineer must 

spot-check the equipment, procedures, 

and recordkeeping as necessary to 

determine compliance with the 

applicable documents incorporated by 

reference and the regulations under this 

part. 

§ 585.711 [Reserved] 

§ 585.712 What are the CVA’s or project 

engineer’s reporting requirements? 

(a) The CVA or project engineer must 

prepare and submit to you and BOEM 

all reports required by this subpart. The 

CVA or project engineer must also 

submit interim reports to you and 

BOEM, as requested by the BOEM. 

(b) For each report required by this 

subpart, the CVA or project engineer 

must submit one electronic copy and 

one paper copy of each final report to 

BOEM. In each report, the CVA or 

project engineer must: 

(1) Give details of how, by whom, and 

when the CVA or project engineer 

activities were conducted; 

(2) Describe the CVA’s or project 

engineer’s activities during the 

verification process; 

(3) Summarize the CVA’s or project 

engineer’s findings; and 

(4) Provide any additional comments 

that the CVA or project engineer deems 

necessary. 

§ 585.713 What must I do after the CVA or 

project engineer confirms conformance 

with the Fabrication and Installation Report 

on my commercial lease? 

After the CVA or project engineer files 

the certification report, you must notify 

BOEM within 10 business days after 

commencing commercial operations. 

§ 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 selfinspections? 

(a) You must develop a 

comprehensive annual self-inspection 

plan covering all of your facilities. You 

must keep this plan wherever you keep 

your records and make it available to 

BOEM inspectors upon request. Your 

plan must specify: 

(1) The type, extent, and frequency of 

in-place inspections that you will 

conduct for both the above-water and 

the below-water structures of all 

facilities and pertinent components of 

the mooring systems for any floating 

facilities; and 

(2) How you are monitoring the 

corrosion protection for both the abovewater and below-water structures. 

(b) You must submit a report annually 

to us no later than November 1 that 

must include: 

(1) A list of facilities inspected in the 

preceding 12 months; 

(2) The type of inspection employed, 

(i.e., visual, magnetic particle, 

ultrasonic testing); and 

(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 either 

install, construct, or acquire by a BOEMapproved assignment a facility, cable, or 

pipeline, or you create an obstruction to 

other uses of the OCS. 

§ 585.902 What are the general 

requirements for decommissioning for 

facilities authorized under my SAP, COP, or 

GAP? 

(a) Except as otherwise authorized by 

BOEM under § 585.909, within 2 years 

following termination of a lease or grant, 

you must: 

(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 MarineRelated Activities Using Existing OCS 

Facilities 

Regulated Activities 

§ 585.1000 What activities does this 

subpart regulate? 

(a) This subpart provides the general 

provisions for authorizing and 

regulating activities that use (or propose 

to use) an existing OCS facility for 

energy- or marine-related purposes, that 

are not otherwise authorized under any 

other part of this subchapter or any 

other applicable Federal statute. 

Activities authorized under any other 

part of this subchapter or under any 

other Federal law that use (or propose 

to use) an existing OCS facility are not 

subject to this subpart. 

(b) BOEM will issue an Alternate Use 

RUE for activities authorized under this 

subpart. 

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(c) At the discretion of the Director, 

an Alternate Use RUE may: 

(1) Permit alternate use activities to 

occur at an existing facility that is 

currently in use under an approved OCS 

lease; or 

(2) Limit alternate use activities at the 

existing facility until after previously 

authorized activities at the facility have 

ceased and the OCS lease terminates. 

§§ 585.1001–585.1003 [Reserved] 

Requesting an Alternate Use RUE 

§ 585.1004 What must I do before I request 

an Alternate Use RUE? 

If you are not the owner of the 

existing facility on the OCS and the 

lessee of the area in which the facility 

is located, you must contact the lessee 

and owner of the facility and reach a 

preliminary agreement as to the 

proposed activity for the use of the 

existing facility. 

§ 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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Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations 64779 

§ 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 requirements 

will be determined by BOEM on a caseby-case basis, and will be included in 

the terms of each Alternate Use RUE. 

(b) Decommissioning activities must 

be completed within 1 year of 

termination of the Alternate Use RUE. 

(c) If you fail to satisfy all 

decommissioning requirements within 

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64780 Federal Register / Vol. 76, No. 201 / Tuesday, October 18, 2011 / Rules and Regulations 

the prescribed time period, we will call 

for the forfeiture of your bond or other 

financial guarantee, and you will remain 

liable for all accidents or damages that 

might result from such failure. 

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 

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