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

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Information about this document as published in the Federal Register.

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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.

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FOR FURTHER INFORMATION CONTACT:

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

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SUPPLEMENTARY INFORMATION:

Background

Order of Events

On May 19, 2010, the Secretary of the Department of the Interior (Secretary) issued Secretarial Order No. 3299, which announced the restructuring of the former Minerals Management Service (MMS). The restructuring divided the responsibilities of the former MMS into three new bureaus within the Department of the Interior:

(1) Bureau of Ocean Energy Management (BOEM).

(2) Bureau of Safety and Environmental Enforcement (BSEE).

(3) Office of Natural Resources Revenue (ONRR).

On June 18, 2010, the Secretary issued Secretarial Order No. 3302, which announced the name change of the former MMS to Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE). This name, BOEMRE, will be in effect until the new organizations are in place October 1, 2011.

On October 1, 2010, the functions of the former Minerals Revenue Management (MRM) officially transferred to ONRR, reporting to the Assistant Secretary for Policy, Management and Budget.

On October 4, 2010, ONRR published a final rule in the Federal Register (75 FR 61051), moving the regulations related to its royalty and revenue functions from 30 CFR chapter II to chapter XII.

October 1, 2011 will be the effective date of the separation of the [remaining components of] BOEMRE into BOEM and BSEE.

Responsibilities

Secretarial Order No. 3299 established the responsibilities for BOEM, BSEE, and ONRR as follows:

BOEM will be responsible for conventional (e.g., oil and gas) and renewable energy-related management functions including, but not limited to, activities involving resource evaluation, planning, and leasing, environmental science, and environmental analysis.

BSEE will be responsible for safety and environmental enforcement functions including, but not limited to, the authority to permit activities, inspect, investigate, summon witnesses and produce evidence: levy penalties; cancel or suspend activities; and oversee safety, response and removal preparedness.

ONRR is responsible for royalty and revenue management functions including, but not limited to, royalty and revenue collection, distribution, auditing and compliance, investigation and enforcement, and asset management for both onshore and offshore activities.

Secretarial Order No. 3299 further established that BOEM and BSEE will be under the supervision of the Assistant Secretary for Land and Minerals Management (ASLM) and that ONRR will be under the supervision of the Assistant Secretary for Policy, Management and Budget. This order also directed the ASLM to “take appropriate steps to ensure that this reorganization will provide that agency decisions are made in compliance with all applicable safety, environmental, and conservation laws and regulations * * *” The reorganization of these regulations supports this directive.

In a January 19, 2011, statement, the Secretary established the missions and functions of BOEM and BSEE as follows:

  • BOEM Mission: Responsible for managing development of the nation's offshore resources in an environmentally and economically responsible way.
  • BOEM Functions include: Leasing, Plan Administration, Environmental Studies, National Environmental Policy Act (NEPA) Analysis, Resource Evaluation, Economic Analysis, and the Renewable Energy Program.
  • BSEE Mission: Enforce safety and environmental regulations.
  • BSEE Functions include: All field operations including Permitting and Research, Inspections, Research, Offshore Regulatory Programs, Oil Spill Response, and newly formed Training and Environmental Compliance functions.

Rulemaking Procedure

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

Proposed Rule

BOEM and BSEE will also jointly issue a proposed rule that will address some more substantive changes to the regulations. In part, the proposed rule will address regulatory anomalies created by splitting the functions of one Start Printed Page 64433agency 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:

○ Change § 250.101(a) to 550.101(a)),

○ Change § 250.123 to 30 CFR 250.123,

○ 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 cross-references to earlier approvals or other actions taken under redesignated sections. This rule replaces the cross-references to previous sections with cross-references to new sections.

Forms and Information Collection

BOEM and BSEE will rename forms as either BOEM or BSEE forms; MMS will be removed from the form names. Each form will retain its already assigned number, except that all numbers will now be four digits. We will add a zero(s) in front of an existing form number where necessary (e.g., form MMS-123 will now become form BSEE-0123). The forms themselves are not changed by this rule.

There are no Information Collection (IC) burden changes in this rule.

Assignment of Regulations and Explanations

All sections that BSEE retains keep their existing numbers, reflecting their existing location in 30 CFR chapter II. BOEM citations are renumbered using the number “5” as the first number for the part, reflecting their new location in 30 CFR chapter V.

The following table (Table A) provides an overview of the assignment of regulations between BOEM and BSEE, by part. Many parts are retained in their entirety by BSEE or moved in their entirety to BOEM. Additional details of how other parts are divided between the two bureaus follow in Tables B through O.

Table A—Derivation Table

Title 30—Mineral Resources

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

Current partNew locationJustification
Subchapter A—Minerals Revenue Management
Part 203—Relief or Reduction in Royalty RatesRetained in its entirety in BSEE, chapter IIBSEE 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 BonusesMoved in its entirety to BOEM, chapter V, part 519BOEM 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 ShelfResponsibilities divided between BOEM and BSEEBoth 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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Part 251—Geological and Geophysical (G&G) Explorations of the Outer Continental ShelfResponsibilities divided between BOEM and BSEEBOEM 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 ProgramBoth BOEM and BSEE will have this part in its entiretyPart 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 FacilitiesMoved to BOEM in its entirety, chapter V, part 553BOEM 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 LineRetained in its entirety in BSEEAll 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 ShelfResponsibilities divided between BOEM and BSEEBOEM 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: DefinitionsMoved to BOEM in its entirety, chapter V, part 559BOEM is responsible for leasing activities. Further details are provided in Table H.
Part 260—Outer Continental Shelf Oil and Gas LeasingMoved to BOEM in its entirety, chapter V, part 560BOEM is responsible for leasing activities. Further details are provided in Table I.
Part 270—Nondiscrimination in the Outer Continental ShelfBoth BOEM and BSEE will have this part in its entiretyBoth 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 ShelfMoved to BOEM in its entirety, chapter V, part 580This 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 ShelfMoved to BOEM in its entirety, chapter V, part 581This 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 SulphurResponsibilities divided between BOEM and BSEEBoth 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 ShelfMoved in its entirety to BOEM, chapter V, part 585At 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 ProceduresBoth BOEM and BSEE will have this part in its entiretyAppeal 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 ActRetained in its entirety in BSEEThis part deals with access to pipelines. All aspects of pipelines, including operations are under the responsibility of BSEE. Further details are provided in Table P.
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The reorganization of the individual parts and subparts is as follows:

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 applicabilityBoth BSEE and BOEM, § 550.101Establishes 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, § 550.102This 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, § 550.103This 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, § 550.104This 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 DefinitionsBoth BSEE and BOEM, § 550.105This 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 BSEEThis 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 BSEEThis 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 BSEEAddresses 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 BSEEThese 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 BSEEAddresses 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 550.117Addresses 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 BSEEAddresses gas injection operations that are under the authority of BSEE.
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§ 250.119 Will MMS approve subsurface gas storage?Moved to BOEM, § 550.119Addresses 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 BSEThese 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 § 550.122This 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, § 550.123This section allows gas storage on unleased lands, through a right-of-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 BSEEThis section addresses gas injection operations. Offshore operations are under the authority of BSEE.
§ 250.125 Service feesBoth BSEE and BOEM, § 550.125Both BSEE and BOEM will oversee activities that require collection of a service fee.
§ 250.126 Electronic payment instructionsBoth BSEE and BOEM, § 550.126Provides information on how to pay the fees collected by BSEE and BOEM.
§ 250.130 Why does MMS conduct inspections?Retained by BSEEBSEE 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 BSEEBSEE 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 550.136BSEE 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 onlyBoth 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, § 550.141This 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, § 550.142This 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, § 550.143This 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, § 550.144This 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, § 550.145This 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, § 550.146This 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 BSEEThis 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 BSEEThis 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 BSEEThis 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 BSEEThis 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 BSEEThis section provides information on the required identification signs that must be displayed that are under the authority of BSEE.
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§ 250.160 When will MMS grant me a right-of-use and easement, and what requirements must I meet?Moved to BOEM, § 550.160This 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, § 550.161This 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, § 550.162This 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, § 550.163This 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 right-of-use and easement?Moved to BOEM, § 550.164This 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, § 550.165This 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, § 550.166This 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 BSEEThese 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 BSEEThese 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 BSEEThis section addresses suspension of operations. Offshore operations are under the authority of BSEE.
§ 250.176 Does a suspension affect my royalty payment?Retained by BSEEThese 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 BSEEThis 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, § 550.181This 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, § 550.182This 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, § 550.183This 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, § 550.184This 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, § 550.185This section addresses lease cancellations. Offshore lease administration, including lease terms, is under the authority of BOEM.
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§ 250.186 What reporting information and report forms must I submit?Both BSEE and BOEM, § 550.186This 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 BSEEThis 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 BSEEThis section addresses incident reporting requirements for offshore operations that are under the authority of BSEE.
§ 250.189 Reporting requirements for incidents requiring immediate notificationRetained by BSEEThis section addresses incident reporting requirements for offshore operations that are under the authority of BSEE.
§ 250.190 Reporting requirements for incidents requiring written notificationRetained by BSEEThis 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 BSEEThis 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 BSEEThis 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 violationsRetained by BSEEThis 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 referenceBOEM 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 BSEEThis 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 costsBoth BSEE and BOEM, § 550.196Data 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 inspectionBOEM—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 referenceRetained by BSEEThis 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 collectionBoth BSEE and BOEM, § 550.199This 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 DefinitionsBoth BSEE and BOEM, § 550.200Definitions 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, § 550.201This 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, § 550.202This 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, § 550.203This section addresses plans that are the responsibility of BOEM.
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§ 250.204 How must I protect the rights of the Federal Government?Retained by BSEEThis 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 BSEEThis 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, § 550.206This section addresses plans that are the responsibility of BOEM.
§ 250.207 What ancillary activities may I conduct?Moved to BOEM, § 550.207This section is under the responsibility of BOEM.
§ 250.208 If I conduct ancillary activities, what notices must I provide?Moved to BOEM, § 550.208This section is under the responsibility of BOEM.
§ 250.209 What is the MMS review process for the notice?Moved to BOEM, § 550.209This 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, § 550.210This section is under the responsibility of BOEM.
§ 250.211 What must the EP include?Moved to BOEM, § 550.211This section addresses plans that are the responsibility of BOEM.
§ 250.212 What information must accompany the EP?Moved to BOEM, § 550.212This section addresses plans that are the responsibility of BOEM.
§ 250.213 What general information must accompany the EP?Moved to BOEM, § 550.213This 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, § 550.214This section addresses plans that are the responsibility of BOEM.
§ 250.215 What hydrogen sulfide (H2 S) information must accompany the EP?Moved to BOEM, § 550.215This section addresses plans that are the responsibility of BOEM.
§ 250.216 What biological, physical, and socioeconomic information must accompany the EP?Moved to BOEM, § 550.216This 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, § 550.217This section addresses plans that are the responsibility of BOEM.
§ 250.218 What air emissions information must accompany the EP?Moved to BOEM, § 550.218This 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, § 550.219This 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, § 550.220This section addresses plans that are the responsibility of BOEM.
§ 250.221 What environmental monitoring information must accompany the EP?Moved to BOEM, § 550.221This section addresses plans that are the responsibility of BOEM.
§ 250.222 What lease stipulations information must accompany the EP?Moved to BOEM, § 550.222This section addresses plans that are the responsibility of BOEM.
§ 250.223 What mitigation measures information must accompany the EP?Moved to BOEM, § 550.223This 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, § 550.224This 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, § 550.225This 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, § 550.226This section addresses plans that are the responsibility of BOEM.
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§ 250.227 What environmental impact analysis (EIA) information must accompany the EP?Moved to BOEM, § 550.227This section addresses plans that are the responsibility of BOEM.
§ 250.228 What administrative information must accompany the EP?Moved to BOEM, § 550.228This section addresses plans that are the responsibility of BOEM.
§ 250.231 After receiving the EP, what will MMS do?Moved to BOEM, § 550.231This 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, § 550.232This 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, § 550.233This 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, § 550.234This 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, § 550.235This section addresses plans that are the responsibility of BOEM.
§ 250.241 What must the DPP or DOCD include?Moved to BOEM, § 550.241This section addresses plans that are the responsibility of BOEM.
§ 250.242 What information must accompany the DPP or DOCD?Moved to BOEM, § 550.242This section addresses plans that are the responsibility of BOEM.
§ 250.243 What general information must accompany the DPP or DOCD?Moved to BOEM, § 550.243This 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, § 550.244This section addresses plans that are the responsibility of BOEM.
§ 250.245 What hydrogen sulfide (H2 S) information must accompany the DPP or DOCD?Moved to BOEM, § 550.245This 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, § 550.246This 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, § 550.247This 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, § 550.248This section addresses plans that are the responsibility of BOEM.
§ 250.249 What air emissions information must accompany the DPP or DOCD?Moved to BOEM, § 550.249This 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, § 550.250This 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, § 550.251This section addresses plans that are the responsibility of BOEM.
§ 250.252 What environmental monitoring information must accompany the DPP or DOCD?Moved to BOEM, § 550.252This section addresses plans that are the responsibility of BOEM.
§ 250.253 What lease stipulations information must accompany the DPP or DOCD?Moved to BOEM, § 550.253This section addresses plans that are the responsibility of BOEM.
§ 250.254 What mitigation measures information must accompany the DPP or DOCD?Moved to BOEM, § 550.254This section addresses plans that are the responsibility of BOEM.
§ 250.255 What decommissioning information must accompany the DPP or DOCD?Moved to BOEM, § 550.255This section addresses plans that are the responsibility of BOEM.
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§ 250.256 What related facilities and operations information must accompany the DPP or DOCD?Moved to BOEM, § 550.256This 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, § 550.257This 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, § 550.258This section addresses plans that are the responsibility of BOEM.
§ 250.259 What sulphur operations information must accompany the DPP or DOCD?Moved to BOEM, § 550.259This 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, § 550.260This 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, § 550.261This section addresses plans that are the responsibility of BOEM.
§ 250.262 What administrative information must accompany the DPP or DOCD?Moved to BOEM, § 550.262This section addresses plans that are the responsibility of BOEM.
§ 250.266 After receiving the DPP or DOCD, what will MMS do?Moved to BOEM, § 550.266This 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, § 550.267This section addresses plans that are the responsibility of BOEM.
§ 250.268 How does MMS respond to recommendations?Moved to BOEM, § 550.268This 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, § 550.269This 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, § 550.270This section addresses plans that are the responsibility of BOEM.
§ 250.271 For what reasons will MMS disapprove the DPP or DOCD?Moved to BOEM, § 550.271This 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, § 550.272This 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, § 550.273This 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, § 550.280This 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, § 550.281This section addresses plans that are the responsibility of BOEM.
§ 250.282 Do I have to conduct post-approval monitoring?Both BSEE and BOEM, § 550.282Both 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, § 550.283This 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, § 550.284This 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, § 550.285This section addresses plans that are the responsibility of BOEM.
§ 250.286 What is a DWOP?Retained by BSEEThis section addresses DWOPs that are part of Field Operations and under the authority of BSEE.
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§ 250.287 For what development projects must I submit a DWOP?Retained by BSEEThis 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 BSEEThis 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 BSEEThis 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 BSEEThis 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 BSEEThis section addresses DWOPs that are part of Field Operations and under the authority of BSEE.
§ 250.292 What must the DWOP contain?Retained by BSEEThis 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 BSEEThis 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 BSEEThis 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 BSEEThis 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, § 550.296This 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, § 550.297This 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, § 550.298This 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, § 550.299This 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 preventionRetained by BSEEThis section addresses pollution prevention during offshore operations. Offshore operations are under the authority of BSEE.
§ 250.301 Inspection of facilitiesRetained by BSEEBSEE will be responsible for all inspection activities on the OCS.
§ 250.302 Definitions concerning air qualityMoved to BOEM, § 550.302This 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 PlanMoved to BOEM, § 550.303This section pertains to air quality concerns that are under the authority of BOEM.
§ 250.304 Existing facilitiesMoved to BOEM, § 550.304This section pertains to air quality concerns that are under the authority of BOEM.
Subpart D—Oil and Gas Drilling Operations
Retained in its entirety by BSEE. This section addresses oil and gas drilling operations on the OCS. Offshore operations are under the authority of BSEE.
Subpart E—Oil and Gas Well-Completion Operations
Retained in its entirety by BSEE. BSEE will oversee all well-operations, under Field Operations, under its authority for ensuring safety and environmental compliance on the OCS.
Subpart F—Oil and Gas Well-Workover Operations
Retained in its entirety by BSEE. This subpart addresses Oil and Gas Well Workover Operations on the OCS. Offshore operations are the responsibility of BSEE, under its authority for ensuring safety and environmental compliance on the OCS.
Subpart G—[Reserved]
Subpart H—Oil and Gas Production Safety Systems
Retained in its entirety by BSEE. Addresses oil and gas production safety systems used during offshore operations, which are under the authority of BSEE.
Subpart I—Platforms and Structures
Retained in its entirety by BSEE. This section addresses platforms and structures on the OCS for offshore operations. Offshore operations are under the authority of BSEE.
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Subpart J—Pipelines and Pipeline Rights-of-Way
Mostly retained by BSEE, except for provisions related to bond requirements (§ 250.1011). Bonding for all activities is the responsibility of BOEM, and the bonding section will be moved to § 550.1011. The rest of pipeline operations, including the issuance of pipeline rights-of-way, are under the authority of BSEE.
§ 250.1000 General requirements.Retained by BSEEThis 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 DefinitionsRetained by BSEEThis 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 pipelinesRetained by BSEEThis 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 pipelinesRetained by BSEEThis 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 pipelinesRetained by BSEEThis 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 pipelinesRetained by BSEEThis 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 BSEEThis 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 applicationsRetained by BSEEThis 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 ReportsRetained by BSEEThis 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 grantsRetained by BSEEThis 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 holdersRetained by BSEEThe 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 holdersMoved to BOEM, § 550.1011All bonding is under the authority of BOEM.
§ 250.1012 Required payments for pipeline right-of-way holdersRetained by BSEEThe 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 grantsRetained by BSEEThe 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-of-way grants expireRetained by BSEEThe 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 grantsRetained by BSEEThe 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-wayRetained by BSEEThe 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-of-way grantsRetained by BSEEThe 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 grantsRetained by BSEEThe 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 grantsRetained by BSEEThe 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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§ 250.1150 What are the general reservoir production requirements?Retained by BSEEThis 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 BSEEThis 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 BSEEThis 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, § 550.1153BOEM 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, § 550.1154BOEM 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, § 550.1155BOEM 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 BSEEThis 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 BSEEThis 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 BSEEThis 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 BSEEThis 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 BSEEThis 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 BSEEThis 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 BSEEThis 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 BSEEThis 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 H2 S?Retained by BSEEThis 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 BOEMThis section addresses information to be submitted; both BSEE and BOEM functions.
Subpart L—Oil and Gas Production Measurement, Surface Commingling, and Security
Retained in its entirety by BSEE. This subpart addresses production measurement, which is a responsibility of BSEE, under its authority for regulatory enforcement of conservation compliance.
Subpart M—Unitization
Retained in its entirety by BSEE. This subpart addresses unitization, which is a responsibility of BSEE, under its authority for regulatory enforcement of conservation compliance.
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Subpart N—Outer Continental Shelf (OCS) Civil Penalties
Retained in both bureaus in its entirety, with the exception of provisions in current § 250.1460 that are specific to operational violations penalized only by BSEE. BOEM issues civil penalties for violations that occur prior to commencement of lease operations and not involving 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 DefinitionsBoth BSEE and BOEM, § 551.1Definitions section, the same definitions apply to both bureaus.
§ 251.2 Purpose of this partMoved to BOEM, § 551.2This section addresses prelease G&G activities. Prelease activities are under the authority of BOEM.
§ 251.3 Authority and applicability of this partBoth BSEE and BOEM, § 551.3This 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 NoticesMoved to BOEM, § 551.4This section addresses prelease G&G activities. Prelease activities are under the authority of BOEM.
§ 251.5 Applying for permits or filing NoticesMoved to BOEM, § 551.5This section addresses prelease G&G activities. Prelease activities are under the authority of BOEM.
§ 251.6 Obligations and rights under a permit or a NoticeMoved to BOEM, § 551.6This section addresses prelease G&G activities. Prelease activities are under the authority of BOEM.
§ 251.7 Test drilling activities under a permitResponsibilities divided between both BSEE and BOEMAll 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 permitMoved to BOEM, § 551.8This 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 permitMoved to BOEM, § 551.9This section addresses prelease G&G activities. Prelease activities are under the authority of BOEM.
§ 251.10 Penalties and appealsMoved to BOEM, § 551.10This 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 partiesMoved to BOEM, § 551.11This section addresses prelease G&G activities. Prelease activities are under the authority of BOEM.
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§ 251.12 Submission, inspection, and selection of geophysical data and information collected under a permit and processed by permittees or third partiesMoved to BOEM, § 551.12This 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 costsMoved to BOEM, § 551.13This 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 permitMoved to BOEM, § 551.14This section addresses prelease G&G activities. Prelease activities are under the authority of BOEM.
§ 251.15 Authority for information collectionIn both BSEE and BOEM § 551.15This 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 PurposeIn both BSEE and BOEM § 552.1Both 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 DefinitionsIn both BSEE and BOEM § 552.2Definitions 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 ProgramIn both BSEE and BOEM § 552.3Both BSEE and BOEM will collect.
§ 252.4 Summary Report to affected StatesIn both BSEE and BOEM § 552.4Both BSEE and BOEM will collect.
§ 252.5 Information to be made available to affected StatesIn both BSEE and BOEM § 552.5Both BSEE and BOEM will collect.
§ 252.6 Freedom of Information Act requirementsIn both BSEE and BOEM § 552.6Both BSEE and BOEM will collect.
§ 252.7 Privileged and proprietary data and information to be made available to affected StatesIn both BSEE and BOEM § 552.7Both 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.Start Printed Page 64447

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, § 553.1BOEM 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, § 553.3BOEM 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, § 553.5BOEM 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, § 553.10BOEM is responsible for all activities related to financial assurance.
§ 253.11 Who must demonstrate OSFR?Moved to BOEM, § 553.11BOEM 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, § 553.12BOEM is responsible for all activities related to financial assurance.
§ 253.13 How much OSFR must I demonstrate?Moved to BOEM, § 553.13BOEM 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, § 553.14BOEM is responsible for all activities related to financial assurance.
§ 253.15 What are my general OSFR compliance responsibilities?Moved to BOEM, § 553.15BOEM 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, § 553.20BOEM is responsible for all activities related to financial assurance.
§ 253.21 How can I use self-insurance as OSFR evidence?Moved to BOEM, § 553.21BOEM 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, § 553.22BOEM 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, § 553.23BOEM 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, § 553.24BOEM 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, § 553.25BOEM 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, § 553.26BOEM 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, § 553.27BOEM 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, § 553.28BOEM is responsible for all activities related to financial assurance.
§ 253.29 How can I use insurance as OSFR evidence?Moved to BOEM, § 553.29BOEM is responsible for all activities related to financial assurance.
§ 253.30 How can I use an indemnity as OSFR evidence?Moved to BOEM, § 553.30BOEM is responsible for all activities related to financial assurance.
§ 253.31 How can I use a surety bond as OSFR evidence?Moved to BOEM, § 553.31BOEM is responsible for all activities related to financial assurance.
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§ 253.32 Are there alternative methods to demonstrate OSFR?Moved to BOEM, § 553.32BOEM 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, § 553.40BOEM is responsible for all activities related to financial assurance.
§ 253.41 What terms must I include in my OSFR evidence?Moved to BOEM, § 553.41BOEM is responsible for all activities related to financial assurance.
§ 253.42 How can I amend my list of COFs?Moved to BOEM, § 553.42BOEM 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, § 553.43BOEM 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, § 553.45BOEM 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, § 553.50BOEM is responsible for all activities related to financial assurance.
§ 253.51 What are the penalties for not complying with this part?Moved to BOEM, § 553.51BOEM 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, § 553.60BOEM is responsible for all activities related to financial assurance.
§ 253.61 When is a guarantor subject to direct action for claims?Moved to BOEM, § 553.61BOEM 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, § 553.62BOEM is responsible for all activities related to financial assurance.
Appendix—Appendix to Part 253—List of U.S. Geological Survey Topographic MapsMoved to BOEM, Appendix to part 553BOEM 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 spill-response plan?Retained in its entirety in BSEE, chapter IIAll 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 IIAll 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 IIAll 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 IIAll oil spill related regulations, except for financial responsibility, are under BSEE, under its responsibility for oil spill response.
§ 254.5 General response plan requirementsRetained in its entirety in BSEE, chapter IIAll oil spill related regulations, except for financial responsibility, are under BSEE, under its responsibility for oil spill response.
§ 254.6 DefinitionsRetained in its entirety in BSEE, chapter IIAll 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 IIAll oil spill related regulations, except for financial responsibility, are under BSEE, under its responsibility for oil spill response.
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§ 254.8 May I appeal decisions under this part?Retained in its entirety in BSEE, chapter IIAll 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 IIAll 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 PurposeRetained in its entirety in BSEE, chapter IIAll 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 IIAll 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 IIAll 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 IIAll 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 IIAll 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 IIAll 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 IIAll 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 IIAll 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 IIAll 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 IIAll 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 IIAll 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 RecordsRetained in its entirety in BSEE, chapter IIAll oil spill related regulations, except for financial responsibility, are under BSEE, under its responsibility for oil spill response.
§ 254.41 Training your response personnelRetained in its entirety in BSEE, chapter IIAll 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 equipmentRetained in its entirety in BSEE, chapter IIAll 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 equipmentRetained in its entirety in BSEE, chapter IIAll 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 capacitiesRetained in its entirety in BSEE, chapter IIAll 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 equipmentRetained in its entirety in BSEE, chapter IIAll 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 IIAll 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 scenarioRetained in its entirety in BSEE, chapter IIAll 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 lineRetained in its entirety in BSEE, chapter IIAll 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 planRetained in its entirety in BSEE, chapter IIAll 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 planRetained in its entirety in BSEE, chapter IIAll oil spill related regulations, except for financial responsibility, are under BSEE, under its responsibility for oil spill response.
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§ 254.53 Submitting a response plan developed under State requirementsRetained in its entirety in BSEE, chapter IIAll 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 lineRetained in its entirety in BSEE, chapter IIAll 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 collectionMoved to BOEM, § 556.0This section addresses leasing activities on the OCS that are under the authority of BOEM.
§ 256.1 PurposeMoved to BOEM, § 556.1, retained purpose except for right-of-way grant clause; under BSEE retained right-of-way grant clauseThis section addresses leasing activities on the OCS that are under the authority of BOEM.
§ 256.2 PolicyMoved to BOEM, § 556.2This section addresses leasing activities on the OCS that are under the authority of BOEM.
§ 256.4 AuthorityMoved to BOEM, § 556.4This section addresses leasing activities on the OCS that are under the authority of BOEM.
§ 256.5 DefinitionsMoved to BOEM, § 556.5This section addresses leasing activities on the OCS that are under the authority of BOEM.
§ 256.7 Cross referencesBoth BSEE and BOEM § 556.7This section contains cross references that are pertinent to both BSEE and BOEM activities.
§ 256.8 Leasing maps and diagramsMoved to BOEM, § 556.8This section addresses leasing activities on the OCS that are under the authority of BOEM.
§ 256.10 Information to StatesMoved to BOEM, § 556.10This section addresses leasing activities on the OCS that are under the authority of BOEM.
§ 256.11 HeliumMoved to BOEM, § 556.11This section addresses leasing activities on the OCS that are under the authority of BOEM.
§ 256.12 Supplemental salesMoved to BOEM, § 556.12This 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 participationMoved to BOEM, § 556.16This section addresses leasing activities on the OCS that are under the authority of BOEM.
§ 256.17 Review by State and local governments and other personsMoved to BOEM, § 556.17This section addresses leasing activities on the OCS that are under the authority of BOEM.
§ 256.19 Periodic consultation with interested partiesMoved to BOEM, § 556.19This section addresses leasing activities on the OCS that are under the authority of BOEM.
§ 256.20  Consideration of coastal zone management programMoved to BOEM, § 556.20This section addresses leasing activities on the OCS that are under the authority of BOEM.
Subpart C—Reports From Federal Agencies
§ 256.22 GeneralMoved to BOEM, § 556.22This 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 areasMoved to BOEM, § 556.23This section addresses leasing activities on the OCS that are under the authority of BOEM.
§ 256.25 Areas near coastal statesMoved to BOEM, § 556.25This section addresses leasing activities on the OCS that are under the authority of BOEM.
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Subpart E—Area Identification and Tract Size
§ 256.26 GeneralMoved to BOEM, § 556.26This section addresses leasing activities on the OCS that are under the authority of BOEM.
§ 256.28 Tract sizeMoved to BOEM, § 556.28This section addresses leasing activities on the OCS that are under the authority of BOEM.
Subpart F—Lease Sales
§ 256.29 Proposed notice of saleMoved to BOEM, § 556.29This section addresses leasing activities on the OCS that are under the authority of BOEM.
§ 256.31 State commentsMoved to BOEM, § 556.31This section addresses leasing activities on the OCS that are under the authority of BOEM.
§ 256.32 Notice of saleMoved to BOEM, § 556.32This section addresses leasing activities on the OCS that are under the authority of BOEM.
Subpart G—Issuance of Leases
§ 256.35 Qualifications of lesseesMoved to BOEM, § 556.35This section addresses leasing activities on the OCS that are under the authority of BOEM.
§ 256.37 Lease termMoved to BOEM, § 556.37This section addresses leasing activities on the OCS that are under the authority of BOEM.
§ 256.38 Joint bidding provisionsMoved to BOEM, § 556.38This section addresses leasing activities on the OCS that are under the authority of BOEM.
§ 256.40 DefinitionsMoved to BOEM, § 556.40This section addresses leasing activities on the OCS that are under the authority of BOEM.
§ 256.41 Joint bidding requirementsMoved to BOEM, § 556.41This section addresses leasing activities on the OCS that are under the authority of BOEM.
§ 256.43 Chargeability for productionMoved to BOEM, § 556.43This section addresses leasing activities on the OCS that are under the authority of BOEM.
§ 256.44 Bids disqualifiedMoved to BOEM, § 556.44This section addresses leasing activities on the OCS that are under the authority of BOEM.
§ 256.46 Submission of bidsMoved to BOEM, § 556.46This section addresses leasing activities on the OCS that are under the authority of BOEM.
§ 256.47 Award of leasesMoved to BOEM, § 556.47This section addresses leasing activities on the OCS that are under the authority of BOEM.
§ 256.49 Lease formMoved to BOEM, § 556.49This section addresses leasing activities on the OCS that are under the authority of BOEM.
§ 256.50 Dating of leasesMoved to BOEM, § 556.50This 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 leaseMoved to BOEM, § 556.52This section addresses leasing activities on the OCS that are under the authority of BOEM.
§ 256.53 Additional bondsMoved to BOEM, § 556.53This section addresses leasing activities on the OCS that are under the authority of BOEM.
§ 256.54 General requirements for bondsMoved to BOEM, § 556.54This section addresses leasing activities on the OCS that are under the authority of BOEM.
§ 256.55 Lapse of bondMoved to BOEM, § 556.55This section addresses leasing activities on the OCS that are under the authority of BOEM.
§ 256.56 Lease-specific abandonment accountsMoved to BOEM, § 556.56This section addresses leasing activities on the OCS that are under the authority of BOEM.
§ 256.57 Using a third-party guarantee instead of a bondMoved to BOEM, § 556.57This 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 bondMoved to BOEM, § 556.58This section addresses leasing activities on the OCS that are under the authority of BOEM.
§ 256.59 Forfeiture of bonds and/or other securitiesMoved to BOEM, § 556.59This 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 leaseMoved to BOEM, § 556.62This section addresses leasing activities on the OCS that are under the authority of BOEM.
§ 256.63 Service feesMoved to BOEM, § 556.63This section addresses leasing activities on the OCS that are under the authority of BOEM.
§ 256.64 How to file transfersMoved to BOEM, § 556.64This section addresses leasing activities on the OCS that are under the authority of BOEM.
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§ 256.65 Attorney General reviewMoved to BOEM, § 556.65This section addresses leasing activities on the OCS that are under the authority of BOEM.
§ 256.67 Separate filings for assignmentsMoved to BOEM, § 556.67This section addresses leasing activities on the OCS that are under the authority of BOEM.
§ 256.68 Effect of assignment of a particular tractMoved to BOEM, § 556.68This section addresses leasing activities on the OCS that are under the authority of BOEM.
§ 256.70 Extension of lease by drilling or well reworking operationsBoth BSEE and BOEM § 556.70Needed by both agencies.
§ 256.71 Directional drillingBoth BSEE and BOEM § 556.71Needed by both agencies.
§ 256.72 Compensatory payments as productionBoth BSEE and BOEM § 556.72Needed by both agencies.
§ 256.73 Effect of suspensions on lease termRetained by BSEEThis 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 leasesMoved to BOEM, § 556.76This section addresses leasing administration on the OCS that are under the authority of BOEM.
§ 256.77 Cancellation of leasesBoth BSEE and BOEM, § 556.77BOEM is authorized to cancel leases. BSEE has the authority to initiate lease cancellation.
Subpart L—Section 6 Leases
§ 256.79 Effect of regulations on leaseBoth BSEE and BOEM § 556.79Needed by both agencies.
§ 256.80 Leases of other mineralsMoved to BOEM, § 556.80This section addresses leasing administration on the OCS that are under the authority of BOEM.
Subpart M—Studies
§ 256.82 Environmental studiesMoved to BOEM, § 556.82This 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, § 556.90This 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, § 556.91This 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, § 556.92This 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, § 556.93This 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, § 556.94This 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, § 556.95This 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 BidMoved to BOEM, APPENDIX A PART 556This 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 559Start Printed Page 64453

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 scopeMoved to BOEM, § 559.001This section addresses definitions used in lease administration under the authority of BOEM.
§ 259.002 DefinitionsMoved to BOEM, § 559.002This 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, § 560.1This 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, § 560.2This 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, § 560.3This 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, § 560.101This 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, § 560.102This 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, § 560.110This 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, § 560.111This 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, § 560.112This 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, § 560.113This 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, § 560.114This 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, § 560.115This 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, § 560.116This 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, § 560.120This 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, § 560.121This 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, § 560.122This 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, § 560.123This section addresses leasing activities on the OCS that are under the authority of BOEM.
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§ 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, § 560.124This 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, § 560.130This 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, § 560.301This 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, § 560.302This 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, § 560.303This 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 PurposeRevised in both BSEE and BOEM § 570.1This 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 partRevised in both BSEE and BOEM § 570.2This section addresses the nondiscrimination on the OCS provisions that are under the authority of both BSEE and BOEM.
§ 270.3 DefinitionsRevised in both BSEE and BOEM § 570.3This section addresses the nondiscrimination on the OCS provisions that are under the authority of both BSEE and BOEM.
§ 270.4 Discrimination prohibitedRevised in both BSEE and BOEM § 570.4This section addresses the nondiscrimination on the OCS provisions that are under the authority of both BSEE and BOEM.
§ 270.5 ComplaintRevised in both BSEE and BOEM § 570.5This section addresses the nondiscrimination on the OCS provisions that are under the authority of both BSEE and BOEM.
§ 270.6 ProcessRevised in both BSEE and BOEM § 570.6This section addresses the nondiscrimination on the OCS provisions that are under the authority of both BSEE and BOEM.
§ 270.7 RemediesRevised in both BSEE and BOEM § 570.7This 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, § 580.1This 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, § 580.2This section addresses activities within the scope of oil, gas and sulphur prospecting on the OCS under BOEM.
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§ 280.3 What requirements must I follow when I conduct prospecting or research activities?Moved to BOEM, § 580.3This 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, § 580.4This 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, § 580.10This 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, § 580.11This 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, § 580.12This 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, § 580.13This 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, § 580.20This 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, § 580.21This 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, § 580.22This 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, § 580.23This 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, § 580.24This 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, § 580.25This 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, § 580.26This 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, § 580.27This 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, § 580.28This 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, § 580.29This 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, § 580.30This 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, § 580.31This 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, § 580.32This 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, § 580.33This 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, § 580.34This 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, § 580.40This 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, § 580.41This 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, § 580.42This section addresses activities within the scope of oil, gas, and sulphur prospecting on the OCS under BOEM.
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§ 280.50 When do I notify MMS that geophysical data and information are available for submission, inspection, and selection?Moved to BOEM, § 580.50This 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, § 580.51This 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, § 580.52This 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, § 580.60This 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, § 580.61This 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, § 580.70This 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, § 580.71This 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, § 580.72This 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, § 580.73This 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 collectionMoved to BOEM, § 580.80This 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 collectionMoved to BOEM, § 581.0This 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 applicabilityMoved to BOEM, § 581.1This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
§ 281.2 AuthorityMoved to BOEM, § 581.2This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
§ 281.3 DefinitionsMoved to BOEM, § 581.3This 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 lesseesMoved to BOEM, § 581.4This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
§ 281.5 False statementsMoved to BOEM, § 581.5This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
§ 281.6 AppealsMoved to BOEM, § 581.6This 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 publicMoved to BOEM, § 581.7This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
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§ 281.8 Rights to mineralsMoved to BOEM, § 581.8This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
§ 281.9 Jurisdictional controversiesMoved to BOEM, § 581.9This 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 saleMoved to BOEM, § 581.11This 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 interestMoved to BOEM, § 581.12This 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 coordinationMoved to BOEM, § 581.13This 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 identificationMoved to BOEM, § 581.14This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
§ 281.15 Tract sizeMoved to BOEM, § 581.15This 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 noticeMoved to BOEM, § 581.16This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
§ 281.17 Leasing noticeMoved to BOEM, § 581.17This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
§ 281.18 Bidding systemMoved to BOEM, § 581.18This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
§ 281.19 Lease termMoved to BOEM, § 581.19This 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 bidsMoved to BOEM, § 581.20This 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 leasesMoved to BOEM, § 581.21This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
§ 281.22 Lease formMoved to BOEM, § 581.22This 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 leasesMoved to BOEM, § 581.23This 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 PaymentsMoved to BOEM, § 581.26This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
§ 281.27 Annual rentalMoved to BOEM, § 581.27This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
§ 281.28 RoyaltyMoved to BOEM, § 581.28This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
§ 281.29 Royalty valuationMoved to BOEM, § 581 29This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
§ 281.30 Minimum royaltyMoved to BOEM, § 581.30This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
§ 281.31 Overriding royaltiesMoved to BOEM, § 581.31This 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 royaltyMoved to BOEM, § 581.32This 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 requirementsMoved to BOEM, § 581.33This 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 thereinMoved to BOEM, § 581.40This 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 transfersMoved to BOEM, § 581.41This 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 leaseMoved to BOEM, § 581.42This 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 termMoved to BOEM, § 581.43This 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 leasesMoved to BOEM, § 581.46This 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 leasesMoved to BOEM, § 581.47This section addresses activities within the scope of leasing of minerals other than oil, gas, and sulphur on the OCS under BOEM.
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Part 282—Operations in the Outer Continental Shelf for Minerals Other Than Oil, Gas, and Sulphur

Both BOEM and BSEE have responsibilities for operations conducted under a mineral lease for OCS minerals other than oil, gas, or sulphur.

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

These responsibilities were divided between the bureaus as follows:

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 collectionBoth BSEE and BOEM § 582.0Both agencies need the authority for information collection.
§ 282.1 Purpose and authorityBoth BSEE and BOEM § 582.1Needed by both agencies.
§ 282.2 ScopeBoth BSEE and BOEM § 582.2Needed by both agencies.
§ 282.3 DefinitionsBoth BSEE and BOEM § 582.3Needed by both agencies.
§ 282.4 Opportunities for review and commentMoved to BOEM, § 582.4BOEM responsibility.
§ 282.5 Disclosure of data and information to the publicBoth BSEE and BOEM § 582.5Needed by both agencies.
§ 282.6 Disclosure of data and information to an adjacent StateBoth BSEE and BOEM § 582.6Needed by both agencies.
§ 282.7 Jurisdictional controversiesBoth BSEE and BOEM § 582.7Needed by both agencies.
Subpart B—Jurisdiction and Responsibilities of Director
§ 282.10 Jurisdiction and responsibilities of DirectorBoth BSEE and BOEM § 582.10Needed by both agencies.
§ 282.11 Director's authorityMoved to BOEM, § 582.11. Paragraph (d) on mining units is in bothParagraph (d) involves units, which is a BSEE function. Paragraph (d) also contains BOEM responsibilities as it mentions plans.
§ 282.12 Director's responsibilitiesResponsibilities are shared by both BSEE and BOEMParagraphs (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 operationsRetained in BSEESuspensions are under the authority of BSEE.
§ 282.14 Noncompliance, remedies, and penaltiesBoth BSEE and BOEM § 582.14BSEE is responsible for addressing noncompliance, remedies, and penalties. Needed in both agencies.
§ 282.15 Cancellation of leasesMoved to BOEM, § 582.15BOEM is responsible for lease administration.
Subpart C—Obligations and Responsibilities of Lessees
§ 282.20 Obligations and responsibilities of lesseesMoved to BOEM, § 582.20This section addresses obligations and responsibilities of lessees that are the responsibility of BOEM.
§ 282.21 Plans, generalMoved to BOEM, § 582.21, except paragraph (e), which is in bothThis 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 PlanMoved to BOEM, § 582.22This section addresses plans that are the responsibility of BOEM.
§ 282.23 Testing PlanMoved to BOEM, § 582.23This section addresses plans that are the responsibility of BOEM.
§ 282.24 Mining PlanMoved to BOEM, § 582.24This section addresses plans that are the responsibility of BOEM.
§ 282.25 Plan modificationMoved to BOEM, § 582.25This section addresses plans that are the responsibility of BOEM.
§ 282.26 Contingency PlanMoved to BOEM, § 582.26This section addresses plans that are the responsibility of BOEM.
§ 282.27 Conduct of operationsRetained in BSEE. Paragraph (i) also in BOEM, § 582.27Paragraph (i) addresses plans that are the responsibility of BOEM.
§ 282.28 Environmental protection measuresMoved 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 bothParagraphs (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 recordsMoved to BOEM, § 582.29A resource evaluation function under BOEM.
§ 282.30 Right of use and easementMoved to BOEM, § 582.30BOEM has the authority to grant rights of use and easement.
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§ 282.31 Suspension of production or other operationsRetained in BSEEBSEE has the authority to suspend production or other operations.
Subpart D—Payments
§ 282.40 BondsMoved to BOEM, § 582.40Financial assurance is a BOEM function with a cross reference provided for BSEE.
§ 282.41 Method of royalty calculationBoth BSEE and BOEM, § 582.41ONRR regulations at 30 CFR part 1206 may apply. Otherwise, lessees must comply with BOEM's procedures specified in lease notices.
§ 282.42 PaymentsMoved to BOEM, § 582.42BOEM.
Subpart E—Appeals
§ 282.50 AppealsBoth BSEE and BOEM, § 582.50Both 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 § 590.1Both BSEE and BOEM need to provide opportunity for appeals of decisions.
§ 290.2 Who may appeal?Both BSEE and BOEM § 590.2Both 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 § 590.3Both BSEE and BOEM. need to provide opportunity for appeals of decisions.
§ 290.4 How do I file an appeal?Both BSEE and BOEM § 590.4Both 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 § 590.5Both BSEE and BOEM need to provide opportunity for appeals of decisions.
§ 290.6 Are informal resolutions permitted?Both BSEE and BOEM § 590.6Both 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 § 590.7Both BSEE and BOEM need to provide opportunity for appeals of decisions.
§ 290.8 How do I exhaust my administrative remedies?Both BSEE and BOEM § 590.8Both 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 IIThis section addresses information collection authority for open and nondiscriminatory access to oil and gas pipelines under OCSLA. Offshore operations are under the authority of BSEE.
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§ 291.100 What is the purpose of this part?Retained in its entirety in BSEE, chapter IIThis 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 IIThis 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 IIThis 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 IIThis 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 IIThis 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 IIThis 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 IIThis 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 IIThis 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 IIThis 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 IIThis 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 IIThis 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 IIThis 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 IIThis 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 IIThis 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 IIThis 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 IIThis 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 Start Printed Page 64461the 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.

Start List of Subjects

List of Subjects

End List of Subjects Start Signature

Dated: August 18, 2011.

Ned Farquhar,

Deputy Assistant Secretary—Land and Minerals Management.

End Signature

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

Start Amendment Part

1. Chapter II is revised to read as follows:

End Amendment Part

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

SUBCHAPTER A—MINERALS REVENUE MANAGEMENT

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

Start Part

PART 203—RELIEF OR REDUCTION IN ROYALTY RATES

Subpart A—General Provisions

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?Start Printed Page 64463
203.31
If I have a qualified phase 2 or qualified phase 3 ultra-deep well, what royalty relief would that well earn for my lease?
203.32
What other requirements or restrictions apply to royalty relief for a qualified phase 2 or phase 3 ultra-deep well?
203.33
To which production do I apply the RSV earned by qualified phase 2 and phase 3 ultra-deep wells on my lease or in my unit?
203.34
To which production may an RSV earned by qualified phase 2 and phase 3 ultra-deep wells on my lease not be applied?
203.35
What administrative steps must I take to use the RSV earned by a qualified phase 2 or phase 3 ultra-deep well?
203.36
Do I keep royalty relief if prices rise significantly?
Royalty Relief for Drilling Deep Gas Wells on Leases Not Subject to Deep Water Royalty Relief
203.40
Which leases are eligible for royalty relief as a result of drilling a deep well or a phase 1 ultra-deep well?
203.41
If I have a qualified deep well or a qualified phase 1 ultra-deep well, what royalty relief would my lease earn?
203.42
What conditions and limitations apply to royalty relief for deep wells and phase 1 ultra-deep wells?
203.43
To which production do I apply the RSV earned from qualified deep wells or qualified phase 1 ultra-deep wells on my lease?
203.44
What administrative steps must I take to use the royalty suspension volume?
203.45
If I drill a certified unsuccessful well, what royalty relief will my lease earn?
203.46
To which production do I apply the royalty suspension supplements from drilling one or two certified unsuccessful wells on my lease?
203.47
What administrative steps do I take to obtain and use the royalty suspension supplement?
203.48
Do I keep royalty relief if prices rise significantly?
203.49
May I substitute the deep gas drilling provisions in this part for the deep gas royalty relief provided in my lease terms?
Royalty Relief for End-of-Life Leases
203.50
Who may apply for end-of-life royalty relief?
203.51
How do I apply for end-of-life royalty relief?
203.52
What criteria must I meet to get relief?
203.53
What relief will BSEE grant?
203.54
How does my relief arrangement for an oil and gas lease operate if prices rise sharply?
203.55
Under what conditions can my end-of-life royalty relief arrangement for an oil and gas lease be ended?
203.56
Does relief transfer when a lease is assigned?
Royalty Relief for Pre-Act Deep Water Leases and for Development and Expansion Projects
203.60
Who may apply for royalty relief on a case-by-case basis in deep water in the Gulf of Mexico or offshore of Alaska?
203.61
How do I assess my chances for getting relief?
203.62
How do I apply for relief?
203.63
Does my application have to include all leases in the field?
203.64
How many applications may I file on a field or a development project?
203.65
How long will BSEE take to evaluate my application?
203.66
What happens if BSEE does not act in the time allowed?
203.67
What economic criteria must I meet to get royalty relief on an authorized field or project?
203.68
What pre-application costs will BSEE consider in determining economic viability?
203.69
If my application is approved, what royalty relief will I receive?
203.70
What information must I provide after BSEE approves relief?
203.71
How does BSEE allocate a field's suspension volume between my lease and other leases on my field?
203.72
Can my lease receive more than one suspension volume?
203.73
How do suspension volumes apply to natural gas?
203.74
When will BSEE reconsider its determination?
203.75
What risk do I run if I request a redetermination?
203.76
When might BSEE withdraw or reduce the approved size of my relief?
203.77
May I voluntarily give up relief if conditions change?
203.78
Do I keep relief approved by BSEE under this part for my lease, unit or project if prices rise significantly?
203.79
How do I appeal BSEE's decisions related to royalty relief for a deepwater lease or a development or expansion project?
203.80
When can I get royalty relief if I am not eligible for royalty relief under other sections in the subpart?
Required Reports
203.81
What supplemental reports do royalty-relief applications require?
203.82
What is BSEE's authority to collect this information?
203.83
What is in an administrative information report?
203.84
What is in a net revenue and relief justification report?
203.85
What is in an economic viability and relief justification report?
203.86
What is in a G&G report?
203.87
What is in an engineering report?
203.88
What is in a production report?
203.89
What is in a cost report?
203.90
What is in a fabricator's confirmation report?
203.91
What is in a post-production development report?
Subpart C—Federal and Indian Oil [Reserved] Subpart D—Federal and Indian Gas [Reserved] Subpart E—Solid Minerals, General [Reserved] Subpart F [Reserved] Subpart G—Other Solid Minerals [Reserved] Subpart H—Geothermal Resources [Reserved] Subpart I—OCS Sulfur [Reserved]
Start Authority

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.

End Authority

Subpart A—General Provisions

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 Start Printed Page 64464reports 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, tension-leg platform, multiple well project, etc.).

(4) For a lease issued in a planning area offshore Alaska, or in the GOM after November 28, 2000, the project must involve a new well drilled into a reservoir that has not previously produced.

(5) On a lease in the GOM, the project must not include a reservoir the production from which an RSV under §§ 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 non-converted lease; or

(2) Before May 3, 2009, on all other leases located in water partly or entirely less than 200 meters deep; or

(3) Before May 3, 2013, on a lease that is located in water entirely more than 200 meters and entirely less than 400 meters deep.

Phase 3 ultra-deep well means an ultra-deep well for which drilling began on or after May 18, 2007, and that begins production:

(1) On or after the date which is 5 years after the lease issuance date on a non-converted lease; or

(2) On or after May 3, 2009, on all other leases located in water partly or entirely less than 200 meters deep; or

(3) On or after May 3, 2013, on a lease that is located in water entirely more Start Printed Page 64465than 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 ultra-deep well.

Redetermination means our reconsideration of our determination on royalty relief because you request it after:

(1) We have rejected your application;

(2) We have granted relief but you want a larger suspension volume;

(3) We withdraw approval; or

(4) You renounce royalty relief.

Renounce means action you take to give up relief after we have granted it and before you start production.

Reservoir means an underground accumulation of oil or natural gas, or both, characterized by a single pressure system and segregated from other such accumulations.

Royalty suspension (RS) lease means a lease that:

(1) Is issued as part of an OCS lease sale held after November 28, 2000;

(2) Is in locations or planning areas specified in a particular Notice of OCS Lease Sale offering that lease; and

(3) Is offered subject to a royalty suspension specified in a Notice of OCS Lease Sale published in the Federal Register.

Royalty suspension supplement (RSS) means a royalty suspension volume resulting from drilling a certified unsuccessful well that is applied to future natural gas and oil production generated at any drilling depth on, or allocated under a BSEE-approved unit agreement to, the same lease.

Royalty suspension volume (RSV) means a volume of production from a lease that is not subject to royalty under the provisions of this part.

Sidetrack means, for the purpose of this subpart, a well resulting from drilling an additional hole to a new objective bottom-hole location by leaving a previously drilled hole. A sidetrack also includes drilling a well from a platform slot reclaimed from a previously drilled well or re-entering and deepening a previously drilled well. A bypass from a sidetrack (e.g., drilling around material blocking the hole, or to straighten crooked holes) is part of the sidetrack.

Sidetrack measured depth means the actual distance or length in feet a sidetrack is drilled beginning where it exits a previously drilled hole to the bottom hole of the sidetrack, that is, to its total depth.

Sunk costs for an authorized field means the after-tax eligible costs that you (not third parties) incur for exploration, development, and production from the spud date of the first discovery on the field to the date we receive your complete application for royalty relief. The discovery well must be qualified as producible under 30 CFR part 550, subpart A. Sunk costs include the rig mobilization and material costs for the discovery well that you incurred before its spud date.

Sunk costs for an expansion or development project means the after-tax eligible costs that you (not third parties) incur for only the first well that encounters hydrocarbons in the reservoir(s) included in the application and that meets the producibility requirements under 30 CFR part 550, subpart A on each lease participating in the application. Sunk costs include rig mobilization and material costs for the discovery wells that you incurred before their spud dates.

Ultra-deep well means either an original well or a sidetrack completed with a perforated interval the top of which is at least 20,000 feet TVD SS. An ultra-deep well subsequently re-perforated less than 20,000 feet TVD SS in the same reservoir is still an ultra-deep well.

Withdraw means action we take on a field that has qualified for relief if you have not met one or more of the performance conditions.

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);Start Printed Page 64466

(4) We find that your new production would not be economic without royalty relief; and

(5) Your lease is on a field that did not produce before enactment of the DWRRA, or if you propose a project to significantly expand production under a Development Operations Coordination Document (DOCD) or a supplementary DOCD, that the Bureau of Ocean Energy Management (BOEM) approved after November 28, 1995.

(d) Under 42 U.S.C. 15904-15905, we may suspend royalties for designated volumes of gas production from deep and ultra-deep wells on a lease if:

(1) Your lease is in shallow water (water less than 400 meters deep) and you produce from an ultra-deep well (top of the perforated interval is at least 20,000 feet TVD SS) or your lease is in waters entirely more than 200 meters and entirely less than 400 meters deep and you produce from a deep well (top of the perforated interval is at least 15,000 feet TVD SS);

(2) Your lease is in the designated area of the GOM (wholly west of 87 degrees, 30 minutes west longitude); and

(3) Your lease is not eligible for deep water royalty relief.

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).
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/​.

How do the provisions in this part apply to different types of leases and projects?

The tables in this section summarize the similar application and approval provisions for the discretionary end-of-life and deep water royalty relief programs in §§ 203.50 to 203.91. Start Printed Page 64467Because 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 elementsEnd-of-life leaseDeep water
Expansion projectPre-act leaseDevelopment project
(1) Administrative information reportXXXX
(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)XXX
(4) G&G reportXXX
(5) Engineering reportXXX
(6) Production reportXXX
(7) Deep water cost reportXXX

(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 elementsEnd-of-life leaseDeep water
Expansion projectPre-act leaseDevelopment project
(1) Fabricator's confirmation reportXXX
(2) Post-production development report approved by an independent certified public accountant (CPA) * * *XXX

(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 conditionsEnd-of-life leaseDeep water
ExpansionPre-act leaseDevelopment project
(1) At least 12 of the last 15 months have the required level of productionX
(2) Already producingX
(3) A producible well into a reservoir that has not produced beforeXXX
(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 reliefXXX

(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 conditionsEnd-of-life leaseDeep water
Expansion projectPre-act leaseDevelopment project
(1) After 12 months under current rate, criteria same as for approvalX
(2) For material change in geologic data, prices, costs, or available technologyXXX

(e) The following table indicates by an X, and §§ 203.53 and 203.69 describe, the characteristics of approved royalty relief.Start Printed Page 64468

Relief rate and volume, subject to certain conditionsEnd-of-life leaseDeep water
Expansion projectPre-act leaseDevelopment 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 volumesX
(2) Qualifying amount is the average monthly production for 12 qualifying monthsX
(3) Zero royalty rate on the suspension volume and the original lease rate on additional productionXXX
(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 regulationsXX
(6) Amount needed to become economicXXX

(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 whenEnd-of-life leaseDeep water
Expansion projectPre-act leaseDevelopment 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 1994XX
(3) Average prices for designated periods exceed levels we specify in the Notice of Sale or the leaseXX

(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 reducedEnd-of-life leaseDeep water
Expansion projectPre-act leaseDevelopment project
(1) If recipient requestsXXXX
(2) Lease royalty rate is at the effective rate for 12 consecutive monthsX
(3) Conditions occur that we specified in the approval letter in individual casesX
(4) Recipient does not submit post-production report that compares expected to actual costsXXX
(5) Recipient changes development systemXXX
(6) Recipient excessively delays starting fabricationXXX
(7) Recipient spends less than 80 percent of proposed pre-production costs prior to start of productionXXX
(8) Amount of relief volume is producedXXX
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

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.Start Printed Page 64469

(a) The lease is located in the GOM wholly west of 87 degrees, 30 minutes West longitude in water depths entirely less than 400 meters deep.

(b) The lease has not produced gas or oil from a deep well or an ultra-deep well, except as provided in § 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.

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 ultra-deep 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 Start Printed Page 64470which 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 ultra-deep 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 ultra-deep well (production begins before the expiration date for the pre-existing relief in its water depth category) and an ultra-deep short sidetrack in § 203.0. However, if it does not begin production until 2010, it earns no RSV because it is too short as a phase 3 ultra-deep well to be a qualified ultra-deep well.

Example 7:

Your lease was issued in June 2004 and expressly incorporates the provisions of §§ 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.

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 non-qualified well.

(e) You owe minimum royalties or rentals in accordance with your lease terms notwithstanding any RSVs allowed under paragraphs (a) and (b) of § 203.31.

(f) Unused RSVs transfer to a successor lessee and expire with the lease.

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 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 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 non-unitized portion of lease A that earns lease A an RSV of 35 BCF under § 203.31, one qualified deep well on the unitized portion Start Printed Page 64471of 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.

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 re-perforated in the same reservoir previously perforated deeper than 15,000 feet TVD SS;

(b) To production from a deep well or ultra-deep well on any other lease, except as provided in paragraph (c) of § 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.

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.

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 non-converted lease issued in OCS Lease Sale 178.
Start Printed Page 64472
(4) $5.83 per MMBtu,(i) The first 20 BCF of RSV earned by a well that is located on a non-converted lease issued in OCS Lease Sales 180, 182, 184, 185, or 187.

(b) For purposes of paragraph (a) of this section, determine the threshold price for any calendar year after 2007 by:

(1) Determining the percentage of change during the year in the Department of Commerce's implicit price deflator for the gross domestic product; and

(2) Adjusting the threshold price for the previous year by that percentage.

(c) The following examples illustrate how this section applies.

Example 1:

Assume that a lessee drills and begins producing from a qualified phase 2 ultra-deep well in 2008 on a lease issued in 2004 in less than 200 meters of water that earns the lease an RSV of 35 BCF. Further, assume the well produces a total of 18 BCF by the end of 2009 and in both of those years, the average daily NYMEX closing natural gas price is less than $10.15 (adjusted for inflation after 2007). The lessee does not pay royalty on the 18 BCF because the gas price threshold under paragraph (a)(1) of this section applies to the first 25 BCF of this RSV earned by this phase 2 ultra-deep well. In 2010, the well produces another 13 BCF. In that year, the average daily closing NYMEX natural gas price is greater than $4.55 per MMBtu (adjusted for inflation after 2007), but less than $10.15 per MMBtu (adjusted for inflation after 2007). The first 7 BCF produced in 2010 will exhaust the first 25 BCF (that is subject to the $10.15 threshold) of the 35 BCF RSV that the well earned. The lessee must pay royalty on the remaining 6 BCF produced in 2010, because it is subject to the $4.55 per MMBtu threshold under paragraph (a)(2)(ii) of this section which was exceeded.

Example 2:

Assume that a lessee:

(1) Drills and produces from well no.1, a qualified deep well in 2008 to a depth of 15,500 feet TVD SS that earns a 15 BCF RSV for the lease under § 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 ultra-deep 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

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.

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.Start Printed Page 64473

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 Start Printed Page 644742 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.

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.

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 BSEE-approved 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 Start Printed Page 64475until 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 re-perforated in the same reservoir previously perforated deeper than 15,000 feet TVD SS;

(2) Production from a deep well or phase 1 ultra-deep well on any other lease, except as provided in paragraph (c) of this section;

(3) Any liquid hydrocarbon (oil and condensate) volumes; or

(4) Production from a deep well or phase 1 ultra-deep well that commenced drilling before:

(i) March 26, 2003, on a lease that is located entirely or partly in water less than 200 meters deep, or

(ii) May 18, 2007, on a lease that is located entirely in water more than 200 meters deep.

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

(a) You must notify the BSEE Regional Supervisor for Production and Development in writing of your intent to begin drilling operations on all deep wells and phase 1 ultra-deep wells; and

(b) Within 30 days of the beginning of production from all wells that would become qualified wells by satisfying the requirements of this section, you must:

(1) Provide written notification to the BSEE Regional Supervisor for Production and Development that production has begun; and

(2) Request confirmation of the size of the royalty suspension volume earned by your lease.

(c) Before beginning production, you must meet any production measurement requirements that the BSEE Regional Supervisor for Production and Development has determined are necessary under 30 CFR part 250, subpart L.

(d) You must provide the information in paragraph (b) of this section by January 20, 2009, if you produced before December 18, 2008, from a qualified deep well or qualified phase 1 ultra-deep well on a lease that is located entirely in water more than 200 meters and less than 400 meters deep.

(e) The BSEE Regional Supervisor for Production and Development may extend the deadline for beginning production for up to one year for a well that cannot begin production before the applicable date prescribed in the definition of “qualified deep well” in § 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.

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.
Start Printed Page 64476
(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.

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 BSEE-approved unit agreement to, the lease on which the certified unsuccessful well was drilled, without regard to the drilling depth of the well producing the gas or oil.

(b) If you have a royalty suspension volume for the lease under § 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 BSEE-approved unit agreement to, your lease.

(d) Unused royalty suspension supplements transfer to a successor lessee and expire with the lease.

(e) You may not apply the RSS allowed under § 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 Start Printed Page 64477suspension supplement remaining at the beginning of that month.

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.

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.

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

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.

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).

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 Start Printed Page 64478relief 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.

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.

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.

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.

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

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).

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.

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.

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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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.

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.

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 forAnd 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.
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.

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.
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 Start Printed Page 64480or 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 pre-Act leases in different categories of water depth, we apply the minimum royalty suspension volume for the deepest such lease then assigned to the field. We base the water depth and makeup of a field on the water-depth delineations in the “Lease Terms and Economic Conditions” map and the “Fields Directory” documents and updates in effect at the time your application is deemed complete. These publications are available from the BSEE Gulf of Mexico Regional Office.

(g) You will get a royalty suspension volume above the minimum if we determine that you need more to make the field or development project economic.

(h) For expansion projects, the minimum royalty suspension volume equals 10 percent of the median of the distribution of known recoverable resources upon which we based approval of your application from all reservoirs included in your project plus any suspension volumes required under § 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.

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 reportWhen due to BSEEDue 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.
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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(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 royalty-suspension volume only if your entire lease is west of 87 degrees, 30 minutes West longitude. If the field lies on both sides of this meridian, only leases located entirely west of the meridian will receive a royalty-suspension volume.

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 royalty-suspension volume, if it meets the evaluation criteria of § 203.67.

(b) An expansion project on your lease may receive a separate royalty-suspension volume, even if we have already granted a royalty-suspension volume to the field that encompasses the project. But the reserves associated with the project must not have been part of our original determination, and the project must meet the evaluation criteria of § 203.67.

How do suspension volumes apply to natural gas?

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

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 Start Printed Page 64482approval 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.

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.

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 post-production 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 post-production development report, you may retain the lesser of 50 percent of the original royalty suspension volume or 50 percent of the median of the distribution of the potentially recoverable resources anticipated in your application.

(d) We granted you a royalty-suspension volume after you qualified for a redetermination under § 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 post-production development report, or you provide false or intentionally inaccurate information that was material to our granting royalty relief under this section. You must pay royalties and late-payment interest determined under 30 U.S.C. 1721 and 30 CFR 1218.54 on all volumes for which you used the royalty suspension. You also may be subject to penalties under other provisions of law.

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.

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.
Start Printed Page 64483

(b) An exception may occur if we determine that the price thresholds in paragraphs (a)(2) or (a)(3) of this section mean the royalty suspension volume set under § 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.

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.

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

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 reportsEnd-of-life leaseDeep water
Expansion projectPre-act leaseDevelopment project
(1) Administrative information ReportXXXX
(2) Net revenue & relief justification reportX
Start Printed Page 64484
(3) Economic viability & relief justification report (RSVP model inputs justified by other required reports)XXX
(4) G&G reportXXX
(5) Engineering reportXXX
(6) Production reportXXX
(7) Deep water cost reportXXX
(8) Fabricator's confirmation reportXXX
(9) Post-production development reportXXX

(b) You must certify that all information in your application, fabricator's confirmation and post-production development reports is accurate, complete, and conforms to the most recent content and presentation guidelines available from the BSEE Regional office for your region.

(c) With your application and post-production development report, you must submit an additional report prepared by an independent CPA that:

(1) Assesses the accuracy of the historical financial information in your report; and

(2) Certifies that the content and presentation of the financial data and information conform to our most recent guidelines on royalty relief. This means the data and information must:

(i) Include only eligible costs that are incurred during the qualification months; and

(ii) Be shown in the proper format.

(d) You must identify the people in the CPA firm who prepared the reports referred to in paragraph (c) of this section and make them available to us to respond to questions about the historical financial information. We may also further review your records to support this information.

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.

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).

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;Start Printed Page 64485

(5) Civil or criminal fines or penalties;

(6) Fees for your royalty relief application; and

(7) Costs associated with existing obligations (e.g., royalty overrides or other forms of payment for acquiring the lease, depreciation on previously acquired equipment or facilities).

(c) We may, in reviewing and evaluating your application, disallow costs when you have not shown they are necessary to operate the lease, or if they are inconsistent with end-of-life operations.

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.

What is in a G&G report?

This report supports the reserve and resource estimates used in the economic evaluation and must contain each of the following elements.

(a) Seismic data which includes:

(1) Non-interpreted 2D/3D survey lines reflecting any available state-of-the-art processing technique in a format readable by BSEE and specified by the deep water royalty relief guidelines;

(2) Interpreted 2D/3D seismic survey lines reflecting any available state-of-the-art processing technique identifying all known and prospective pay horizons, wells, and fault cuts;

(3) Digital velocity surveys in the format of the GOM region's letter to lessees of 10/1/90;

(4) Plat map of “shot points;” and

(5) “Time slices” of potential horizons.

(b) Well data which includes:

(1) Hard copies of all well logs in which—

(i) The 1-inch electric log shows pay zones and pay counts and lithologic and paleo correlation markers at least every 500-feet,

(ii) The 1-inch type log shows missing sections from other logs where faulting occurs,

(iii) The 5-inch electric log shows pay zones and pay counts and labeled points used in establishing resistivity of the formation, 100 percent water saturated (Ro) and the resistivity of the undisturbed formation (Rt), and

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

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

(3) Core data, if available;

(4) Well correlation sections;

(5) Pressure data;

(6) Production test results;

(7) Pressure-volume-temperature analysis, if available; and

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

(c) Map interpretations which includes for each reservoir in the field:

(1) Structure maps consisting of top and base of sand maps showing well and seismic shot point locations;

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

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

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

(d) Reservoir-specific data which includes:

(1) Probability of reservoir occurrence with hydrocarbons;

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

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

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

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

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

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

(8) Reserve or resource distribution by reservoir.

(e) Aggregated reserve and resource data which includes:

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

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

(3) The ranges within the aggregated distribution for reserves and resources that define the development and production scenarios presented in the engineering and production reports. Typically there will be three ranges specified by two positive reserve and resource points on the aggregated distribution. The range at the low end of the distribution will be associated with the conservative development and production scenario; the middle range Start Printed Page 64486will 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.

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.

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.

What is in a cost report?

This report lists all actual and projected costs for your field, must explain and document the source of each cost estimate, and must identify the following elements.

(a) Sunk costs. Report sunk costs in dollars not adjusted for inflation and only if you have documentation.

(b) Appraisal, delineation and development costs. Base them on actual spending, current authorization for expenditure, engineering estimates, or analogous projects. These costs cover:

(1) Platform well drilling and average depth;

(2) Platform well completion;

(3) Subsea well drilling and average depth;

(4) Subsea well completion;

(5) Production system (platform); and

(6) Flowline fabrication and installation.

(c) Production costs based on historical costs, engineering estimates, or analogous projects. These costs cover:

(1) Operation;

(2) Equipment; and

(3) Existing royalty overrides (we will not use the royalty overrides in evaluations).

(d) Transportation costs, based on historical costs, engineering estimates, or analogous projects. These costs cover:

(1) Oil or gas tariffs from pipeline or tankerage;

(2) Trunkline and tieback lines; and

(3) Gas plant processing for natural gas liquids.

(e) Abandonment costs, based on historical costs, engineering estimates, or analogous projects. You should provide the costs to plug and abandon only wells and to remove only production systems for which you have not incurred costs as of the time of application submission. You should also include a point estimate or distribution of prospective salvage value for all potentially reusable facilities and materials, along with the source and an explanation of the figures provided.

(f) A set of cost estimates consistent with each one of up to three field-development scenarios and production profiles (conservative, most likely, optimistic). You should express costs in constant real dollar terms for the base year. You may also express the uncertainty of each cost estimate with a minimum and maximum percentage of the base value.

(g) A spending schedule. You should provide costs for each year (in real dollars) for each category in paragraphs (a) through (f) of this section.

(h) A summary of other costs which are ineligible for evaluating your need for relief. These costs cover:

(1) Expenses before first discovery on the field;

(2) Cash bonuses;

(3) Fees for royalty relief applications;

(4) Lease rentals, royalties, and payments of net profit share and net revenue share;

(5) Legal expenses;

(6) Damages and losses;

(7) Taxes;

(8) Interest or finance charges, including those embedded in equipment leases;

(9) Fines or penalties; and

(10) Money spent on previously existing obligations (e.g., royalty overrides or other forms of payment for acquiring a financial position in a lease, expenditures for plugging wells and removing and abandoning facilities that existed on the application submission date).

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.

What is in a post-production development report?

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

Start Printed Page 64487

Subpart C—Federal and Indian Oil [Reserved]

Subpart D—Federal and Indian Gas [Reserved]

Subpart E—Solid Minerals, General [Reserved]

Subpart F—[Reserved]

Subpart G—Other Solid Minerals [Reserved]

Subpart H—Geothermal Resources [Reserved]

Subpart I—OCS Sulfur [Reserved]

End Part Start Part

PART 219—[RESERVED]

End Part

Subchapter B—Offshore

Start Part

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

Subpart A—General

Authority and Definition of Terms

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.Start Printed Page 64488
250.301
Inspection of facilities.
Subpart D—Oil and Gas Drilling Operations General Requirements
250.400
Who is subject to the requirements of this subpart?
250.401
What must I do to keep wells under control?
250.402
When and how must I secure a well?
250.403
What drilling unit movements must I report?
250.404
What are the requirements for the crown block?
250.405
What are the safety requirements for diesel engines used on a drilling rig?
250.406
What additional safety measures must I take when I conduct drilling operations on a platform that has producing wells or has other hydrocarbon flow?
250.407
What tests must I conduct to determine reservoir characteristics?
250.408
May I use alternative procedures or equipment during drilling operations?
250.409
May I obtain departures from these drilling requirements?
Applying for a Permit to Drill
250.410
How do I obtain approval to drill a well?
250.411
What information must I submit with my application?
250.412
What requirements must the location plat meet?
250.413
What must my description of well drilling design criteria address?
250.414
What must my drilling prognosis include?
250.415
What must my casing and cementing programs include?
250.416
What must I include in the diverter and BOP descriptions?
250.417
What must I provide if I plan to use a mobile offshore drilling unit (MODU)?
250.418
What additional information must I submit with my APD?
Casing and Cementing Requirements
250.420
What well casing and cementing requirements must I meet?
250.421
What are the casing and cementing requirements by type of casing string?
250.422
When may I resume drilling after cementing?
250.423
What are the requirements for pressure testing casing?
250.424
What are the requirements for prolonged drilling operations?
250.425
What are the requirements for pressure testing liners?
250.426
What are the recordkeeping requirements for casing and liner pressure tests?
250.427
What are the requirements for pressure integrity tests?
250.428
What must I do in certain cementing and casing situations?
Diverter System Requirements
250.430
When must I install a diverter system?
250.431
What are the diverter design and installation requirements?
250.432
How do I obtain a departure to diverter design and installation requirements?
250.433
What are the diverter actuation and testing requirements?
250.434
What are the recordkeeping requirements for diverter actuations and tests?
Blowout Preventer (BOP) System Requirements
250.440
What are the general requirements for BOP systems and system components?
250.441
What are the requirements for a surface BOP stack?
250.442
What are the requirements for a subsea BOP system?
250.443
What associated systems and related equipment must all BOP systems include?
250.444
What are the choke manifold requirements?
250.445
What are the requirements for kelly valves, inside BOPs, and drill-string safety valves?
250.446
What are the BOP maintenance and inspection requirements?
250.447
When must I pressure test the BOP system?
250.448
What are the BOP pressure tests requirements?
250.449
What additional BOP testing requirements must I meet?
250.450
What are the recordkeeping requirements for BOP tests?
250.451
What must I do in certain situations involving BOP equipment or systems?
Drilling Fluid Requirements
250.455
What are the general requirements for a drilling fluid program?
250.456
What safe practices must the drilling fluid program follow?
250.457
What equipment is required to monitor drilling fluids?
250.458
What quantities of drilling fluids are required?
250.459
What are the safety requirements for drilling fluid-handling areas?
Other Drilling Requirements
250.460
What are the requirements for conducting a well test?
250.461
What are the requirements for directional and inclination surveys?
250.462
What are the requirements for well-control drills?
250.463
Who establishes field drilling rules?
Applying for a Permit To Modify and Well Records
250.465
When must I submit an Application for Permit to Modify (APM) or an End of Operations Report to BSEE?
250.466
What records must I keep?
250.467
How long must I keep records?
250.468
What well records am I required to submit?
250.469
What other well records could I be required to submit?
Hydrogen Sulfide
250.490
Hydrogen sulfide.
Subpart E—Oil and Gas Well-Completion Operations
250.500
General requirements.
250.501
Definition.
250.502
Equipment movement.
250.503
Emergency shutdown system.
250.504
Hydrogen sulfide.
250.505
Subsea completions.
250.506
Crew instructions.
250.507
[Reserved]
250.508
[Reserved]
250.509
Well-completion structures on fixed platforms.
250.510
Diesel engine air intakes.
250.511
Traveling-block safety device.
250.512
Field well-completion rules.
250.513
Approval and reporting of well-completion operations.
250.514
Well-control fluids, equipment, and operations.
250.515
Blowout prevention equipment.
250.516
Blowout preventer system tests, inspections, and maintenance.
250.517
Tubing and wellhead equipment.
Casing Pressure Management
250.518
What are the requirements for casing pressure management?
250.519
How often do I have to monitor for casing pressure?
250.520
When do I have to perform a casing diagnostic test?
250.521
How do I manage the thermal effects caused by initial production on a newly completed or recompleted well?
250.522
When do I have to repeat casing diagnostic testing?
250.523
How long do I keep records of casing pressure and diagnostic tests?
250.524
When am I required to take action from my casing diagnostic test?
250.525
What do I submit if my casing diagnostic test requires action?
250.526
What must I include in my notification of corrective action?
250.527
What must I include in my casing pressure request?
250.528
What are the terms of my casing pressure request?
250.529
What if my casing pressure request is denied?
250.530
When does my casing pressure request approval become invalid?
Subpart F—Oil and Gas Well-Workover Operations
250.600
General requirements.
250.601
Definitions.
250.602
Equipment movement.
250.603
Emergency shutdown system.
250.604
Hydrogen sulfide.
250.605
Subsea workovers.
250.606
Crew instructions.
250.607
[Reserved]
250.608
[Reserved]
250.609
Well-workover structures on fixed platforms.
250.610
Diesel engine air intakes.
250.611
Traveling-block safety device.
250.612
Field well-workover rules.
250.613
Approval and reporting for well-workover operations.
250.614
Well-control fluids, equipment, and operations.
250.615
Blowout prevention equipment.
250.616
Blowout preventer system testing, records, and drills.
250.617
What are my BOP inspection and maintenance requirements?Start Printed Page 64489
250.618
Tubing and wellhead equipment.
250.619
Wireline operations.
Subpart G—[Reserved] Subpart H—Oil and Gas Production Safety Systems
250.800
General requirements.
250.801
Subsurface safety devices.
250.802
Design, installation, and operation of surface production-safety systems.
250.803
Additional production system requirements.
250.804
Production safety-system testing and records.
250.805
Safety device training.
250.806
Safety and pollution prevention equipment quality assurance requirements.
250.807
Additional requirements for subsurface safety valves and related equipment installed in high pressure high temperature (HPHT) environments.
250.808
Hydrogen sulfide.
Subpart I—Platforms and Structures General Requirements for Platforms
250.900
What general requirements apply to all platforms?
250.901
What industry standards must your platform meet?
250.902
What are the requirements for platform removal and location clearance?
250.903
What records must I keep?
Platform Approval Program
250.904
What is the Platform Approval Program?
250.905
How do I get approval for the installation, modification, or repair of my platform?
250.906
What must I do to obtain approval for the proposed site of my platform?
250.907
Where must I locate foundation boreholes?
250.908
What are the minimum structural fatigue design requirements?
Platform Verification Program
250.909
What is the Platform Verification Program?
250.910
Which of my facilities are subject to the Platform Verification Program?
250.911
If my platform is subject to the Platform Verification Program, what must I do?
250.912
What plans must I submit under the Platform Verification Program?
250.913
When must I resubmit Platform Verification Program plans?
250.914
How do I nominate a CVA?
250.915
What are the CVA's primary responsibilities?
250.916
What are the CVA's primary duties during the design phase?
250.917
What are the CVA's primary duties during the fabrication phase?
250.918
What are the CVA's primary duties during the installation phase?
Inspection, Maintenance, and Assessment of Platforms
250.919
What in-service inspection requirements must I meet?
250.920
What are the BSEE requirements for assessment of fixed platforms?
250.921
How do I analyze my platform for cumulative fatigue?
Subpart J—Pipelines and Pipeline Rights-of-Way
250.1000
General requirements.
250.1001
Definitions.
250.1002
Design requirements for DOI pipelines.
250.1003
Installation, testing, and repair requirements for DOI pipelines.
250.1004
Safety equipment requirements for DOI pipelines.
250.1005
Inspection requirements for DOI pipelines.
250.1006
How must I decommission and take out of service a DOI pipeline?
250.1007
What to include in applications.
250.1008
Reports.
250.1009
Requirements to obtain pipeline right-of-way grants.
250.1010
General requirements for pipeline right-of-way holders.
250.1011
[Reserved]
250.1012
Required payments for pipeline right-of-way holders.
250.1013
Grounds for forfeiture of pipeline right-of-way grants.
250.1014
When pipeline right-of-way grants expire.
250.1015
Applications for pipeline right-of-way grants.
250.1016
Granting pipeline rights-of-way.
250.1017
Requirements for construction under pipeline right-of-way grants.
250.1018
Assignment of pipeline right-of-way grants.
250.1019
Relinquishment of pipeline right-of-way grants.
Subpart K—Oil and Gas Production Requirements General
250.1150
What are the general reservoir production requirements?
Well Tests and Surveys
250.1151
How often must I conduct well production tests?
250.1152
How do I conduct well tests?
250.1153
[Reserved]
Classifying Reservoirs
250.1154
[Reserved]
250.1155
[Reserved]
Approvals Prior to Production
250.1156
What steps must I take to receive approval to produce within 500 feet of a unit or lease line?
250.1157
How do I receive approval to produce gas-cap gas from an oil reservoir with an associated gas cap?
250.1158
How do I receive approval to downhole commingle hydrocarbons?
Production Rates
250.1159
May the Regional Supervisor limit my well or reservoir production rates?
Flaring, Venting, and Burning Hydrocarbons
250.1160
When may I flare or vent gas?
250.1161
When may I flare or vent gas for extended periods of time?
250.1162
When may I burn produced liquid hydrocarbons?
250.1163
How must I measure gas flaring or venting volumes and liquid hydrocarbon burning volumes, and what records must I maintain?
250.1164
What are the requirements for flaring or venting gas containing H2 S?
Other Requirements
250.1165
What must I do for enhanced recovery operations?
250.1166
What additional reporting is required for developments in the Alaska OCS Region?
250.1167
What information must I submit with forms and for approvals?
Subpart L—Oil and Gas Production Measurement, Surface Commingling, and Security
250.1200
Question index table.
250.1201
Definitions.
250.1202
Liquid hydrocarbon measurement.
250.1203
Gas measurement.
250.1204
Surface commingling.
250.1205
Site security.
Subpart M—Unitization
250.1300
What is the purpose of this subpart?
250.1301
What are the requirements for unitization?
250.1302
What if I have a competitive reservoir on a lease?
250.1303
How do I apply for voluntary unitization?
250.1304
How will BSEE require unitization?
Subpart N—Outer Continental Shelf Civil Penalties Outer Continental Shelf Lands Act Civil Penalties
250.1400
How does BSEE begin the civil penalty process?
250.1401
Index table.
250.1402
Definitions.
250.1403
What is the maximum civil penalty?
250.1404
Which violations will BSEE review for potential civil penalties?
250.1405
When is a case file developed?
250.1406
When will BSEE notify me and provide penalty information?
250.1407
How do I respond to the letter of notification?
250.1408
When will I be notified of the Reviewing Officer's decision?
250.1409
What are my appeal rights?
Federal Oil and Gas Royalty Management Act Civil Penalties Definitions
250.1450
What definitions apply to this subpart?
Penalties After a Period To Correct
250.1451
What may BSEE do if I violate a statute, regulation, order, or lease term relating to a Federal oil and gas lease?
250.1452
What if I correct the violation?
250.1453
What if I do not correct the violation?
250.1454
How may I request a hearing on the record on a Notice of Noncompliance?
250.1455
Does my request for a hearing on the record affect the penalties?Start Printed Page 64490
250.1456
May I request a hearing on the record regarding the amount of a civil penalty if I did not request a hearing on the Notice of Noncompliance?
Penalties Without a Period To Correct
250.1460
May I be subject to penalties without prior notice and an opportunity to correct?
250.1461
How will BSEE inform me of violations without a period to correct?
250.1462
How may I request a hearing on the record on a Notice of Noncompliance regarding violations without a period to correct?
250.1463
Does my request for a hearing on the record affect the penalties?
250.1464
May I request a hearing on the record regarding the amount of a civil penalty if I did not request a hearing on the Notice of Noncompliance?
General Provisions
250.1470
How does BSEE decide what the amount of the penalty should be?
250.1471
Does the penalty affect whether I owe interest?
250.1472
How will the Office of Hearings and Appeals conduct the hearing on the record?
250.1473
How may I appeal the Administrative Law Judge's decision?
250.1474
May I seek judicial review of the decision of the Interior Board of Land Appeals?
250.1475
When must I pay the penalty?
250.1476
Can BSEE reduce my penalty once it is assessed?
250.1477
How may BSEE collect the penalty?
Criminal Penalties
250.1480
May the United States criminally prosecute me for violations under Federal oil and gas leases?
Bonding Requirements
250.1490
What standards must my BOEM-specified surety instrument meet?
250.1491
How will BOEM determine the amount of my bond or other surety instrument?
Financial Solvency Requirements
250.1495
How do I demonstrate financial solvency?
250.1496
How will BOEM determine if I am financially solvent?
250.1497
When will BOEM monitor my financial solvency?
Subpart O—Well Control and Production Safety Training
250.1500
Definitions.
250.1501
What is the goal of my training program?
250.1503
What are my general responsibilities for training?
250.1504
May I use alternative training methods?
250.1505
Where may I get training for my employees?
250.1506
How often must I train my employees?
250.1507
How will BSEE measure training results?
250.1508
What must I do when BSEE administers written or oral tests?
250.1509
What must I do when BSEE administers or requires hands-on, simulator, or other types of testing?
250.1510
What will BSEE do if my training program does not comply with this subpart?
Subpart P—Sulphur Operations
250.1600
Performance standard.
250.1601
Definitions.
250.1602
Applicability.
250.1603
Determination of sulphur deposit.
250.1604
General requirements.
250.1605
Drilling requirements.
250.1606
Control of wells.
250.1607
Field rules.
250.1608
Well casing and cementing.
250.1609
Pressure testing of casing.
250.1610
Blowout preventer systems and system components.
250.1611
Blowout preventer systems tests, actuations, inspections, and maintenance.
250.1612
Well-control drills.
250.1613
Diverter systems.
250.1614
Mud program.
250.1615
Securing of wells.
250.1616
Supervision, surveillance, and training.
250.1617
Application for permit to drill.
250.1618
Application for permit to modify.
250.1619
Well records.
250.1620
Well-completion and well-workover requirements.
250.1621
Crew instructions.
250.1622
Approvals and reporting of well-completion and well-workover operations.
250.1623
Well-control fluids, equipment, and operations.
250.1624
Blowout prevention equipment.
250.1625
Blowout preventer system testing, records, and drills.
250.1626
Tubing and wellhead equipment.
250.1627
Production requirements.
250.1628
Design, installation, and operation of production systems.
250.1629
Additional production and fuel gas system requirements.
250.1630
Safety-system testing and records.
250.1631
Safety device training.
250.1632
Production rates.
250.1633
Production measurement.
250.1634
Site security.
Subpart Q—Decommissioning Activities General
250.1700
What do the terms “decommissioning”, “obstructions”, and “facility” mean?
250.1701
Who must meet the decommissioning obligations in this subpart?
250.1702
When do I accrue decommissioning obligations?
250.1703
What are the general requirements for decommissioning?
250.1704
When must I submit decommissioning applications and reports?
Permanently Plugging Wells
250.1710
When must I permanently plug all wells on a lease?
250.1711
When will BSEE order me to permanently plug a well?
250.1712
What information must I submit before I permanently plug a well or zone?
250.1713
Must I notify BSEE before I begin well plugging operations?
250.1714
What must I accomplish with well plugs?
250.1715
How must I permanently plug a well?
250.1716
To what depth must I remove wellheads and casings?
250.1717
After I permanently plug a well, what information must I submit?
Temporary Abandoned Wells
250.1721
If I temporarily abandon a well that I plan to re-enter, what must I do?
250.1722
If I install a subsea protective device, what requirements must I meet?
250.1723
What must I do when it is no longer necessary to maintain a well in temporary abandoned status?
Removing Platforms and Other Facilities
250.1725
When do I have to remove platforms and other facilities?
250.1726
When must I submit an initial platform removal application and what must it include?
250.1727
What information must I include in my final application to remove a platform or other facility?
250.1728
To what depth must I remove a platform or other facility?
250.1729
After I remove a platform or other facility, what information must I submit?
250.1730
When might BSEE approve partial structure removal or toppling in place?
250.1731
Who is responsible for decommissioning an OCS facility subject to an Alternate Use RUE?
Site Clearance for Wells, Platforms, and Other Facilities
250.1740
How must I verify that the site of a permanently plugged well, removed platform, or other removed facility is clear of obstructions?
250.1741
If I drag a trawl across a site, what requirements must I meet?
250.1742
What other methods can I use to verify that a site is clear?
250.1743
How do I certify that a site is clear of obstructions?
Pipeline Decommissioning
250.1750
When may I decommission a pipeline in place?
250.1751
How do I decommission a pipeline in place?
250.1752
How do I remove a pipeline?
250.1753
After I decommission a pipeline, what information must I submit?
250.1754
When must I remove a pipeline decommissioned in place?
Subpart R—[Reserved] Subpart S—Safety and Environmental Management Systems (SEMS)
250.1900
Must I have a SEMS program?
250.1901
What is the goal of my SEMS program?
250.1902
What must I include in my SEMS program?
250.1903
Definitions.
250.1904
Documents incorporated by reference.Start Printed Page 64491
250.1905-250.1908
[Reserved]
250.1909
What are management's general responsibilities for the SEMS program?
250.1910
What safety and environmental information is required?
250.1911
What criteria for hazards analyses must my SEMS program meet?
250.1912
What criteria for management of change must my SEMS program meet?
250.1913
What criteria for operating procedures must my SEMS program meet?
250.1914
What criteria must be documented in my SEMS program for safe work practices and contractor selection?
250.1915
What criteria for training must be in my SEMS program?
250.1916
What criteria for mechanical integrity must my SEMS program meet?
250.1917
What criteria for pre-startup review must be in my SEMS program?
250.1918
What criteria for emergency response and control must be in my SEMS program?
250.1919
What criteria for investigation of incidents must be in my SEMS program?
250.1920
What are the auditing requirements for my SEMS program?
250.1921-250.1923
[Reserved]
250.1924
How will BSEE determine if my SEMS program is effective?
250.1925
May BSEE direct me to conduct additional audits?
250.1926
What qualifications must an independent third party or my designated and qualified personnel meet?
250.1927
What happens if BSEE finds shortcomings in my SEMS program?
250.1928
What are my recordkeeping and documentation requirements?
250.1929
What are my responsibilities for submitting OCS performance measure data?
Start Authority

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

End Authority

Subpart A—General

Authority and Definition of Terms

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.

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.
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.

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.

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 Start Printed Page 64492facilities 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, Start Printed Page 64493secondary 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 column-stabilized-units (CSUs); floating production, storage and offloading facilities (FPSOs); tension-leg platforms (TLPs); spars, etc. They also include facilities for product measurement and royalty determination (e.g., lease Automatic Custody Transfer Units, gas meters) of OCS production on installations not on the OCS. Any group of OCS installations interconnected with walkways, or any group of installations that includes a central or primary installation with processing equipment and one or more satellite or secondary installations is a single facility. The Regional Supervisor may decide that the complexity of the individual installations justifies their classification as separate facilities.

(2) As used in 30 CFR 550.303, means all installations or devices permanently or temporarily attached to the seabed. They include mobile offshore drilling units (MODUs), even while operating in the “tender assist” mode (i.e., with skid-off drilling units) or other vessels engaged in drilling or downhole operations. They are used for exploration, development, and production activities for oil, gas, or sulphur and emit or have the potential to emit any air pollutant from one or more sources. They include all floating production systems (FPSs), including column-stabilized-units (CSUs); floating production, storage and offloading facilities (FPSOs); tension-leg platforms (TLPs); spars, etc. During production, multiple installations or devices are a single facility if the installations or devices are at a single site. Any vessel used to transfer production from an offshore facility is part of the facility while it is physically attached to the facility.

(3) As used in § 250.490(b), means a vessel, a structure, or an artificial island used for drilling, well completion, well-workover, or production operations.

(4) As used in §§ 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 H2 S in concentrations that could potentially result in atmospheric concentrations of 20 ppm or more of H2 S; or

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

H2S present means drilling, logging, coring, testing, or producing operations have confirmed the presence of H2 S in concentrations and volumes that could potentially result in atmospheric concentrations of 20 ppm or more of H2 S.

H2S unknown means the designation of a zone or geologic formation where neither the presence nor absence of H2 S has been confirmed.

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

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

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

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

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

Lessee means a person who has entered into a lease with the United States to explore for, develop, and produce the leased minerals. The term lessee also includes the BOEM-approved assignee of the lease, and the owner or the BOEM-approved assignee of operating rights for the lease.

Major Federal action means any action or proposal by the Secretary that is subject to the provisions of section 102(2)(C) of the National Environmental Policy Act of 1969, 42 U.S.C. (2)(C) (i.e., Start Printed Page 64494an action that will have a significant impact on the quality of the human environment requiring preparation of an environmental impact statement under section 102(2)(C) of the National Environmental Policy Act).

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

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

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

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

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

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

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

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

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

Oil reservoir with an associated gas cap means a reservoir that contains hydrocarbons in both a liquid and gaseous (two-phase) state.

Oil-well completion means a well completed in an oil reservoir or in the oil accumulation of an oil reservoir with an associated gas cap.

Operating rights mean any interest held in a lease with the right to explore for, develop, and produce leased substances.

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

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

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

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

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

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

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

Projected emissions mean emissions, either controlled or uncontrolled, from a source or sources.

Prospect means a geologic feature having the potential for mineral deposits.

Regional Director means the BSEE officer with responsibility and authority for a Region within BSEE.

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

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

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

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

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

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

(4) An unleased block(s).

Routine operations, for the purposes of subpart F, mean any of the following operations conducted on a well with the tree installed:

(1) Cutting paraffin;

(2) Removing and setting pump-through-type tubing plugs, gas-lift valves, and subsurface safety valves that can be removed by wireline operations;

(3) Bailing sand;

(4) Pressure surveys;

(5) Swabbing;

(6) Scale or corrosion treatment;

(7) Caliper and gauge surveys;

(8) Corrosion inhibitor treatment;

(9) Removing or replacing subsurface pumps;

(10) Through-tubing logging (diagnostics);

(11) Wireline fishing;

(12) Setting and retrieving other subsurface flow-control devices; and

(13) Acid treatments.

Sensitive reservoir means a reservoir in which the production rate will affect ultimate recovery.

Significant archaeological resource means those archaeological resources that meet the criteria of significance for eligibility to the National Register of Historic Places as defined in 36 CFR 60.4, or its successor.

Suspension means a granted or directed deferral of the requirement to produce (Suspension of Production (SOP)) or to conduct leaseholding operations (Suspension of Operations (SOO)).

Venting means the release of gas into the atmosphere without igniting it. This includes gas that is released underwater and bubbles to the atmosphere.

Waste of oil, gas, or sulphur means:

(1) The physical waste of oil, gas, or sulphur;Start Printed Page 64495

(2) The inefficient, excessive, or improper use, or the unnecessary dissipation of reservoir energy;

(3) The locating, spacing, drilling, equipping, operating, or producing of any oil, gas, or sulphur well(s) in a manner that causes or tends to cause a reduction in the quantity of oil, gas, or sulphur ultimately recoverable under prudent and proper operations or that causes or tends to cause unnecessary or excessive surface loss or destruction of oil or gas; or

(4) The inefficient storage of oil.

Welding means all activities connected with welding, including hot tapping and burning.

Wellbay is the area on a facility within the perimeter of the outermost wellheads.

Well-completion operations mean the work conducted to establish production from a well after the production-casing string has been set, cemented, and pressure-tested.

Well-control fluid means drilling mud, completion fluid, or workover fluid as appropriate to the particular operation being conducted.

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

Workover operations mean the work conducted on wells after the initial well-completion operation for the purpose of maintaining or restoring the productivity of a well.

You means a lessee, the owner or holder of operating rights, a designated operator or agent of the lessee(s), a pipeline right-of-way holder, or a State lessee granted a right-of-use and easement.

Performance Standards

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.

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.

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.

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.

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 safe-welding areas.

(d) How you will prevent spark-producing activities (i.e., grinding, abrasive blasting/cutting and arc-welding) in hazardous locations.

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.

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.

What procedures must I follow when welding?

(a) Before you weld, you must move any equipment containing hydrocarbons or other flammable substances at least Start Printed Page 6449635 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.

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.

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.

[Reserved]
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 off-unit location, you must pay royalties when the gas is first produced.

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.

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.

[Reserved]
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

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.Start Printed Page 64497

Service—processing of the following:Fee amount30 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.

Start Printed Page 64498
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

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.

Will BSEE notify me before conducting an inspection?

BSEE conducts both scheduled and unscheduled inspections.

What must I do when BSEE conducts an inspection?

(a) When BSEE conducts an inspection, you must provide:

(1) Access to all platforms, artificial islands, and other installations on your leases or associated with your lease, right-of-use and easement, or right-of-way; and

(2) Helicopter landing sites and refueling facilities for any helicopters we use to regulate offshore operations.

(b) You must make the following available for us to inspect:

(1) The area covered under a lease, right-of-use and easement, right-of-way, or permit;

(2) All improvements, structures, and fixtures on these areas; and

(3) All records of design, construction, operation, maintenance, repairs, or investigations on or related to the area.

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

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.

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

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 orallyGive 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).
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.

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.

[Reserved]
[Reserved]
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 Start Printed Page 64499obligations 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.

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)

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.

How do I name facilities in the Pacific Region?

The operator assigns a name to the facility.

How do I name facilities in the Alaska Region?

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

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.

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.

[Reserved]

Suspensions

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).

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; orStart Printed Page 64500

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

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.

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.

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.

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.

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).

When may the Regional Supervisor grant an SOO?

(a) The Regional Supervisor may grant an SOO when necessary to allow you time to begin drilling or other operations when you are prevented by reasons beyond your control, such as unexpected weather, unavoidable accidents, or drilling rig delays.

(b) The Regional Supervisor may grant an SOO when all of the following conditions are met:

(1) The lease was issued with a primary lease term of 5 years, or with a primary term of 8 years with a requirement to drill within 5 years;

(2) Before the end of the third year of the primary term, you or your predecessor in interest must have acquired and interpreted geophysical information that indicates:

(i) The presence of a salt sheet;

(ii) That all or a portion of a potential hydrocarbon-bearing formation may lie beneath or adjacent to the salt sheet; and

(iii) The salt sheet interferes with identification of the potential hydrocarbon-bearing formation.

(3) The interpreted geophysical information required under paragraph (b)(2) of this section must include full 3-D depth migration beneath the salt sheet and over the entire lease area.

(4) Before requesting the suspension, you have conducted or are conducting additional data processing or interpretation of the geophysical information with the objective of identifying a potential hydrocarbon-bearing formation.

(5) You demonstrate that additional time is necessary to:

(i) Complete current processing or interpretation of existing geophysical data or information;

(ii) Acquire, process, or interpret new geophysical data or information; or

(iii) Drill into the potential hydrocarbon-bearing formation identified as a result of the activities conducted in paragraphs (b)(2), (b)(4), and (b)(5) of this section.

(c) The Regional Supervisor may grant an SOO to conduct additional geological and geophysical data analysis that may lead to the drilling of a well below 25,000 feet true vertical depth below the datum at mean sea level (TVD SS) when all of the following conditions are met:

(1) The lease was issued with a primary lease term of:

(i) Five years; or

(ii) Eight years with a requirement to drill within 5 years.

(2) Before the end of the fifth year of the primary term, you or your predecessor in interest must have acquired and interpreted geophysical information that:

(i) Indicates that all or a portion of a potential hydrocarbon-bearing formation lies below 25,000 feet TVD SS; and

(ii) Includes full 3-D depth migration over the entire lease area.

(3) Before requesting the suspension, you have conducted or are conducting additional data processing or interpretation of the geophysical information with the objective of identifying a potential hydrocarbon-bearing geologic structure or stratigraphic trap lying below 25,000 feet TVD SS.

(4) You demonstrate that additional time is necessary to:

(i) Complete current processing or interpretation of existing geophysical data or information;

(ii) Acquire, process, or interpret new geophysical or geological data or Start Printed Page 64501information 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.

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.

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

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.

[Reserved]

Information and Reporting Requirements

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 Start Printed Page 64502or otherwise exempt from public disclosure under law or regulation.

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.

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 (H2 S) gas, as defined in § 250.490(l).

(6) All collisions that result in property or equipment damage greater than $25,000. “Collision” means the act of a moving vessel (including an aircraft) striking another vessel, or striking a stationary vessel or object (e.g., a boat striking a drilling rig or platform). “Property or equipment damage” means the cost of labor and material to restore all affected items to their condition before the damage, including, but not limited to, the OCS facility, a vessel, helicopter, or equipment. It does not include the cost of salvage, cleaning, gas-freeing, dry docking, or demurrage.

(7) All incidents involving structural damage to an OCS facility. “Structural damage” means damage severe enough so that operations on the facility cannot continue until repairs are made.

(8) All incidents involving crane or personnel/material handling operations.

(9) All incidents that damage or disable safety systems or equipment (including firefighting systems).

(b) You must provide a written report of the following incidents to the District Manager within 15 calendar days after the incident:

(1) Any injuries that result in one or more days away from work or one or more days on restricted work or job transfer. One or more days means the injured person was not able to return to work or to all of their normal duties the day after the injury occurred;

(2) All gas releases that initiate equipment or process shutdown;

(3) All incidents that require operations personnel on the facility to muster for evacuation for reasons not related to weather or drills;

(4) All other incidents, not listed in paragraph (a) of this section, resulting in property or equipment damage greater than $25,000.

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.

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.

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 Start Printed Page 64503panel 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.

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

(a) You must submit evacuation statistics to the Regional Supervisor for a natural occurrence, such as a hurricane, a tropical storm, or an earthquake. Statistics include facilities and rigs evacuated and the amount of production shut-in for gas and oil. You must:

(1) Submit the statistics by fax or e-mail (for activities in the BSEE GOM OCS Region, use Form BSEE-0132) as soon as possible when evacuation occurs. In lieu of submitting your statistics by fax or e-mail, you may submit them electronically in accordance with 30 CFR 250.186(a)(3);

(2) Submit the statistics on a daily basis by 11 a.m., as conditions allow, during the period of shut-in and evacuation;

(3) Inform BSEE when you resume production; and

(4) Submit the statistics either by BSEE district, or the total figures for your operations in a BSEE region.

(b) If your facility, production equipment, or pipeline is damaged by a natural occurrence, you must:

(1) Submit an initial damage report to the Regional Supervisor within 48 hours after you complete your initial evaluation of the damage. You must use Form BSEE-0143, Facility/Equipment Damage Report, to make this and all subsequent reports. In lieu of submitting Form BSEE-0143 by fax or e-mail, you may submit the damage report electronically in accordance with 30 CFR 250.186(a)(3). In the report, you must:

(i) Name the items damaged (e.g., platform or other structure, production equipment, pipeline);

(ii) Describe the damage and assess the extent of the damage (major, medium, minor); and

(iii) Estimate the time it will take to replace or repair each damaged structure and piece of equipment and return it to service. The initial estimate need not be provided on the form until availability of hardware and repair capability has been established (not to exceed 30 days from your initial report).

(2) Submit subsequent reports monthly and immediately whenever information submitted in previous reports changes until the damaged structure or equipment is returned to service. In the final report, you must provide the date the item was returned to service.

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.

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.

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.