June 30, 2008
CODE OF FEDERAL REGULATIONS
30
Parts 200 to 699
Revised as of July 1, 2008
Mineral Resources
Containing a codification of documents of general applicability and future effect
As of July 1, 2008
With Ancillaries
Published by
Office of the Federal Register
National Archives and Records
Administration
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Table of Contents
Page
Explanation
v

Title 30:
Chapter II—Minerals Management Service, Department of the Interior
3
Chapter III—Board of Surface Mining and Reclamation Appeals, Department of the Interior
595
Chapter IV—Geological Survey, Department of the Interior
599

Finding Aids:
Material Approved for Incorporation by Reference
613
Table of CFR Titles and Chapters
621
Alphabetical List of Agencies Appearing in the CFR
641
List of CFR Sections Affected
651
Cite this Code:CFR
To cite the regulations in this volume use title, part and section number. Thus, 30 CFR 201.100 refers to title 30, part 201, section 100.

Explanation
The Code of Federal Regulations is a codification of the general and permanent rules published in the Federal Register by the Executive departments and agencies of the Federal Government. The Code is divided into 50 titles which represent broad areas subject to Federal regulation. Each title is divided into chapters which usually bear the name of the issuing agency. Each chapter is further subdivided into parts covering specific regulatory areas.
Each volume of the Code is revised at least once each calendar year and issued on a quarterly basis approximately as follows:
Title 1 through Title 16
as of January 1
Title 17 through Title 27
as of April 1
Title 28 through Title 41
as of July 1
Title 42 through Title 50
as of October 1
The appropriate revision date is printed on the cover of each volume.

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INCORPORATION BY REFERENCE
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What is a proper incorporation by reference? The Director of the Federal Register will approve an incorporation by reference only when the requirements of 1 CFR part 51 are met. Some of the elements on which approval is based are:
(a) The incorporation will substantially reduce the volume of material published in the Federal Register.
(b) The matter incorporated is in fact available to the extent necessary to afford fairness and uniformity in the administrative process.
(c) The incorporating document is drafted and submitted for publication in accordance with 1 CFR part 51.
Properly approved incorporations by reference in this volume are listed in the Finding Aids at the end of this volume.
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Office of the Federal Register.
July 1, 2008.

THIS TITLE
Title 30—Mineral Resources is composed of three volumes. The parts in these volumes are arranged in the following order: parts 1 to 199, parts 200 to 699, and part 700 to End. The contents of these volumes represent all current regulations codified under this title of the CFR as of July 1, 2008.
For this volume, Cheryl E. Sirofchuck was Chief Editor. The Code of Federal Regulations publication program is under the direction of Michael L. White, assisted by Ann Worley.
30 CFR Ch. II (7-1-08 Edition)
Minerals Management Service, Interior

Title 30—Mineral Resources
(This book contains parts 200 to 699)
Part
chapter ii—Minerals Management Service, Department of the Interior
201
chapter iii—Board of Surface Mining and Reclamation Appeals, Department of the Interior
301
chapter iv—Geological Survey, Department of the Interior
401

CHAPTER II—MINERALS MANAGEMENT SERVICE, DEPARTMENT OF THE INTERIOR
(Parts 200 to 699)

SUBCHAPTER A—MINERALS REVENUE MANAGEMENT
Part
Page
201
General
5
202
Royalties
5
203
Relief or reduction in royalty rates
14
204
Alternatives for marginal properties
43
206
Product valuation
50
207
Sales agreements or contracts governing the disposal of lease products
164
208
Sale of Federal royalty oil
165
210
Forms and reports
173
212
Records and files maintenance
186
215
Accounting and auditing standards [Reserved]
217
Audits and inspections
188
218
Collection of monies and provision for geothermal credits and incentives
189
219
Distribution and disbursement of royalties, rentals, and bonuses
205
220
Accounting procedures for determining net profit share payment for Outer Continental Shelf oil and gas leases
206
227
Delegation to States
220
228
Cooperative activities with States and Indian tribes
231
229
Delegation to States
235
230
Recoupments and refunds [Reserved]
232
Interest payments [Reserved]
233
Escrow and investments [Reserved]
234
Bonding—payment liability [Reserved]
241
Penalties
243
242
Orders [Reserved]
243
Suspensions pending appeal and bonding—Minerals revenue management
247

SUBCHAPTER B—OFFSHORE
250
Oil and gas and sulphur operations in the Outer Continental Shelf
253
251
Geological and geophysical (G & G) explorations of the Outer Continental Shelf
454
252
Outer Continental Shelf (OCS) oil and gas information program
467
253
Oil spill financial responsibility for offshore facilities
472
254
Oil-spill response requirements for facilities located seaward of the coast line
486
256
Leasing of sulphur or oil and gas in the Outer Continental Shelf
498
259
Mineral leasing: Definitions
526
260
Outer Continental Shelf oil and gas leasing
527
270
Nondiscrimination in the Outer Continental Shelf
535
280
Prospecting for minerals other than oil, gas, and sulfur on the Outer Continental Shelf
536
281
Leasing of minerals other than oil, gas, and sulphur in the Outer Continental Shelf
548
282
Operations in the Outer Continental Shelf for minerals other than oil, gas, and sulphur
561

SUBCHAPTER C—APPEALS
290
Appeals procedures
584
291
Open and nondiscriminatory access to oil and gas pipelines under the Outer Continental Shelf Lands Act (eff. 8-18-08)
588

SUBCHAPTER A—MINERALS REVENUE MANAGEMENT
Pt. 201

PART 201—GENERAL
Subpart A—General Provisions [Reserved]
Subpart B—Oil and Gas, General [Reserved]

Subpart C—Oil and Gas, Onshore
Sec.
201.100
Responsibilities of the Associate Director for Minerals Revenue Management.
Subpart D—Oil, Gas and Sulphur, Offshore [Reserved]
Subpart E—Coal [Reserved]
Subpart F—Other Solid Minerals [Reserved]
Subpart G—Geothermal Resources [Reserved]
Subpart H—Indian Lands [Reserved]

Authority:
The Act of February 25, 1920 (30 U.S.C. 181, et seq.), as amended; the Act of May 21, 1930 (30 U.S.C. 301-306); the Mineral Leasing Act for Acquired Lands (30 U.S.C. 351-359), as amended; the Act of March 3, 1909 (25 U.S.C. 396), as amended; the National Environmental Policy Act of 1969 (42 U.S.C. 4321, et seq.) as amended; the Act of May 11, 1938 (25 U.S.C. 396a-396q), as amended; the Act of February 28, 1891 (25 U.S.C. 397), as amended; the Act of May 29, 1924 (25 U.S.C. 398); the Act of March 3, 1927 (25 U.S.C. 398a-398e); the Act of June 30, 1919 (25 U.S.C. 399), as amended; R.S. § 441 (43 U.S.C. 1457), see also Attorney General's Opinion of April 2, 1941 (40 Op. Atty. Gen. 41); the Federal Property and Administrative Services Act of 1949 (40 U.S.C. 471, et seq.), as amended; the National Environmental Policy Act of 1969 (42 U.S.C. 4321 et seq.), as amended; the Act of December 12, 1980 (Pub. L. 96-514, 94 Stat. 2964); the Combined Hydrocarbon Leasing Act of 1981 (Pub. L. 97-78, 95 Stat. 1070); the Outer Continental Shelf Lands Act (43 U.S.C. 1331, et seq.), as amended; section 2 of Reorganization Plan No. 3 of 1950 (64 stat. 1262); Secretarial Order No. 3071 of January 19, 1982, as amended; and Secretarial Order 3087, as amended.
Subpart A—General Provisions [Reserved]
Subpart B—Oil and Gas, General [Reserved]

Subpart C—Oil and Gas, Onshore
§ 201.100
Responsibilities of the Associate Director for Minerals Revenue Management.
The Associate Director is responsible for the collection of certain rents, royalties, and other payments; for the receipt of sales and production reports; for determining royalty liability; for maintaining accounting records; for any audits of the royalty payments and obligations; and for any and all other functions relating to royalty management on Federal and Indian oil and gas leases.
[47 FR 47768, Oct. 27, 1982. Redesignated at 48 FR 35641, Aug. 5, 1983]
Subpart D—Oil, Gas and Sulphur, Offshore [Reserved]
Subpart E—Coal [Reserved]
Subpart F—Other Solid Minerals [Reserved]
Subpart G—Geothermal Resources [Reserved]
Subpart H—Indian Lands [Reserved]
Pt. 202

PART 202—ROYALTIES
Subpart A—General Provisions [Reserved]

Subpart B—Oil, Gas, and OCS Sulfur, General
Sec.
202.51
Scope and definitions.
202.52
Royalties.
202.53
Minimum royalty.

Subpart C—Federal and Indian Oil
202.100
Royalty on oil.
202.101
Standards for reporting and paying royalties.

Subpart D—Federal Gas
202.150
Royalty on gas.
202.151
Royalty on processed gas.
202.152
Standards for reporting and paying royalties on gas.
Subpart E—Solid Minerals, General [Reserved]

Subpart F—Coal
202.250
Overriding royalty interest.
Subpart G—Other Solid Minerals [Reserved]

Subpart H—Geothermal Resources
202.350
Scope and definitions.
202.351
Royalties on geothermal resources.
202.352
Minimum royalty.
202.353
Measurement standards for reporting and paying royalties and direct use fees.
Subpart I—OCS Sulfur [Reserved]

Subpart J—Gas Production from Indian Leases
202.550
How do I determine the royalty due on gas production?
202.551
How do I determine the volume of production for which I must pay royalty if my lease is not in an approved Federal unit or communitization agreement (AFA)?
202.552
How do I determine how much royalty I must pay if my lease is in an approved Federal unit or communitization agreement (AFA)?
202.553
How do I value my production if I take more than my entitled share?
202.554
How do I value my production that I do not take if I take less than my entitled share?
202.555
What portion of the gas that I produce is subject to royalty?
202.556
How do I determine the value of avoidably lost, wasted, or drained gas?
202.557
Must I pay royalty on insurance compensation for unavoidably lost gas?
202.558
What standards do I use to report and pay royalties on gas?

Authority:
5 U.S.C. 301 et seq.; 25 U.S.C. 396 et seq., 396a et seq., 2101 et seq.; 30 U.S.C. 181 et seq., 351 et seq., 1001 et seq.; 1701 et seq.; 31 U.S.C. 9701; 43 U.S.C. 1301 et seq.; 1331 et seq., 1801 et seq.
Subpart A—General Provisions [Reserved]

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

Source:
53 FR 1217, Jan. 15, 1988, unless otherwise noted.
§ 202.51
Scope and definitions.
(a) This subpart is applicable to Federal and Indian (Tribal and allotted) oil and gas leases (except leases on the Osage Indian Reservation, Osage County, Oklahoma) and OCS sulfur leases.
(b) The definitions in subparts B, C, D, and E, of part 206 of this title are applicable to subparts B, C, D, and J of this part.
[53 FR 1217, Jan. 15, 1988, as amended at 64 FR 43513, Aug. 10, 1999]
§ 202.52
Royalties.
(a) Royalties on oil, gas, and OCS sulfur shall be at the royalty rate specified in the lease, unless the Secretary, pursuant to the provisions of the applicable mineral leasing laws, reduces, or in the case of OCS leases, reduces or eliminates, the royalty rate or net profit share set forth in the lease.
(b) For purposes of this subpart, the use of the term royalty(ies) includes the term net profit share(s).
§ 202.53
Minimum royalty.
For leases that provide for minimum royalty payments, the lessee shall pay the minimum royalty as specified in the lease.

Subpart C—Federal and Indian Oil
§ 202.100
Royalty on oil.
(a) Royalties due on oil production from leases subject to the requirements of this part, including condensate separated from gas without processing, shall be at the royalty rate established by the terms of the lease. Royalty shall be paid in value unless MMS requires payment in-kind. When paid in value, the royalty due shall be the value, for royalty purposes, determined pursuant to part 206 of this title multiplied by the royalty rate in the lease.
(b)(1) All oil (except oil unavoidably lost or used on, or for the benefit of, the lease, including that oil used off-lease for the benefit of the lease when such off-lease use is permitted by the MMS or BLM, as appropriate) produced from a Federal or Indian lease to which this part applies is subject to royalty.
(2) When oil is used on, or for the benefit of, the lease at a production facility handling production from more than one lease with the approval of the MMS or BLM, as appropriate, or at a production facility handling unitized or communitized production, only that proportionate share of each lease's production (actual or allocated) necessary to operate the production facility may be used royalty-free.
(3) Where the terms of any lease are inconsistent with this section, the lease terms shall govern to the extent of that inconsistency.
(c) If BLM determines that oil was avoidably lost or wasted from an onshore lease, or that oil was drained from an onshore lease for which compensatory royalty is due, or if MMS determines that oil was avoidably lost or wasted from an offshore lease, then the value of that oil shall be determined in accordance with 30 CFR part 206.
(d) If a lessee receives insurance compensation for unavoidably lost oil, royalties are due on the amount of that compensation. This paragraph shall not apply to compensation through self-insurance.
(e)(1) In those instances where the lessee of any lease committed to a federally approved unitization or communitization agreement does not actually take the proportionate share of the agreement production attributable to its lease under the terms of the agreement, the full share of production attributable to the lease under the terms of the agreement nonetheless is subject to the royalty payment and reporting requirements of this title. Except as provided in paragraph (e)(2) of this section, the value, for royalty purposes, of production attributable to unitized or communitized leases will be determined in accordance with 30 CFR part 206. In applying the requirements of 30 CFR part 206, the circumstances involved in the actual disposition of the portion of the production to which the lessee was entitled but did not take shall be considered as controlling in arriving at the value, for royalty purposes, of that portion as though the person actually selling or disposing of the production were the lessee of the Federal or Indian lease.
(2) If a Federal or Indian lessee takes less than its proportionate share of agreement production, upon request of the lessee MMS may authorize a royalty valuation method different from that required by paragraph (e)(1) of this section, but consistent with the purposes of these regulations, for any volumes not taken by the lessee but for which royalties are due.
(3) For purposes of this subchapter, all persons actually taking volumes in excess of their proportionate share of production in any month under a unitization or communitization agreement shall be deemed to have taken ratably from all persons actually taking less than their proportionate share of the agreement production for that month.
(4) If a lessee takes less than its proportionate share of agreement production for any month but royalties are paid on the full volume of its proportionate share in accordance with the provisions of this section, no additional royalty will be owed for that lease for prior periods when the lessee subsequently takes more than its proportionate share to balance its account or when the lessee is paid a sum of money by the other agreement participants to balance its account.
(f) For production from Federal and Indian leases which are committed to federally-approved unitization or communitization agreements, upon request of a lessee MMS may establish the value of production pursuant to a method other than the method required by the regulations in this title if: (1) The proposed method for establishing value is consistent with the requirements of the applicable statutes, lease terms, and agreement terms; (2) persons with an interest in the agreement, including, to the extent practical, royalty interests, are given notice and an opportunity to comment on the proposed valuation method before it is authorized; and (3) to the extent practical, persons with an interest in a Federal or Indian lease committed to the agreement, including royalty interests, must agree to use the proposed method for valuing production from the agreement for royalty purposes.
[53 FR 1217, Jan. 15, 1988]
§ 202.101
Standards for reporting and paying royalties.
Oil volumes are to be reported in barrels of clean oil of 42 standard U.S. gallons (231 cubic inches each) at 60 °F. When reporting oil volumes for royalty purposes, corrections must have been made for Basic Sediment and Water (BS&W) and other impurities. Reported American Petroleum Institute (API) oil gravities are to be those determined in accordance with standard industry procedures after correction to 60 °F.
[53 FR 1217, Jan. 15, 1988]

Subpart D—Federal Gas

Source:
53 FR 1271, Jan. 15, 1988, unless otherwise noted.
§ 202.150
Royalty on gas.
(a) Royalties due on gas production from leases subject to the requirements of this subpart, except helium produced from Federal leases, shall be at the rate established by the terms of the lease. Royalty shall be paid in value unless MMS requires payment in kind. When paid in value, the royalty due shall be the value, for royalty purposes, determined pursuant to 30 CFR part 206 of this title multiplied by the royalty rate in the lease.
(b)(1) All gas (except gas unavoidably lost or used on, or for the benefit of, the lease, including that gas used off-lease for the benefit of the lease when such off-lease use is permitted by the MMS or BLM, as appropriate) produced from a Federal lease to which this subpart applies is subject to royalty.
(2) When gas is used on, or for the benefit of, the lease at a production facility handling production from more than one lease with the approval of MMS or BLM, as appropriate, or at a production facility handling unitized or communitized production, only that proportionate share of each lease's production (actual or allocated) necessary to operate the production facility may be used royalty free.
(3) Where the terms of any lease are inconsistent with this subpart, the lease terms shall govern to the extent of that inconsistency.
(c) If BLM determines that gas was avoidably lost or wasted from an onshore lease, or that gas was drained from an onshore lease for which compensatory royalty is due, or if MMS determines that gas was avoidably lost or wasted from an OCS lease, then the value of that gas shall be determined in accordance with 30 CFR part 206.
(d) If a lessee receives insurance compensation for unavoidably lost gas, royalties are due on the amount of that compensation. This paragraph shall not apply to compensation through self-insurance.
(e)(1) In those instances where the lessee of any lease committed to a Federally approved unitization or communitization agreement does not actually take the proportionate share of the production attributable to its Federal lease under the terms of the agreement, the full share of production attributable to the lease under the terms of the agreement nonetheless is subject to the royalty payment and reporting requirements of this title. Except as provided in paragraph (e)(2) of this section, the value for royalty purposes of production attributable to unitized or communitized leases will be determined in accordance with 30 CFR part 206. In applying the requirements of 30 CFR part 206, the circumstances involved in the actual disposition of the portion of the production to which the lessee was entitled but did not take shall be considered as controlling in arriving at the value for royalty purposes of that portion, as if the person actually selling or disposing of the production were the lessee of the Federal lease.
(2) If a Federal lessee takes less than its proportionate share of agreement production, upon request of the lessee MMS may authorize a royalty valuation method different from that required by paragraph (e)(1) of this section, but consistent with the purpose of these regulations, for any volumes not taken by the lessee but for which royalties are due.
(3) For purposes of this subchapter, all persons actually taking volumes in excess of their proportionate share of production in any month under a unitization or communitization agreement shall be deemed to have taken ratably from all persons actually taking less than their proportionate share of the agreement production for that month.
(4) If a lessee takes less than its proportionate share of agreement production for any month but royalties are paid on the full volume of its proportionate share in accordance with the provisions of this section, no additional royalty will be owed for that lease for prior periods at the time the lessee subsequently takes more than its proportionate share to balance its account or when the lessee is paid a sum of money by the other agreement participants to balance its account.
(f) For production from Federal leases which are committed to federally-approved unitization or communitization agreements, upon request of a lessee MMS may establish the value of production pursuant to a method other than the method required by the regulations in this title if: (1) The proposed method for establishing value is consistent with the requirements of the applicable statutes, lease terms and agreement terms; (2) to the extent practical, persons with an interest in the agreement, including royalty interests, are given notice and an opportunity to comment on the proposed valuation method before it is authorized; and (3) to the extent practical, persons with an interest in a Federal lease committed to the agreement, including royalty interests, must agree to use the proposed method for valuing production from the agreement for royalty purposes.
[53 FR 1271, Jan. 15, 1988, as amended at 64 FR 43513, Aug. 10, 1999]
§ 202.151
Royalty on processed gas.
(a)(1) A royalty, as provided in the lease, shall be paid on the value of:
(i) Any condensate recovered downstream of the point of royalty settlement without resorting to processing; and
(ii) Residue gas and all gas plant products resulting from processing the gas produced from a lease subject to this subpart.
(2) MMS shall authorize a processing allowance for the reasonable, actual costs of processing the gas produced from Federal leases. Processing allowances shall be determined in accordance with 30 CFR part 206 subpart D for gas production from Federal leases and 30 CFR part 206 subpart E for gas production from Indian leases.
(b) A reasonable amount of residue gas shall be allowed royalty free for operation of the processing plant, but no allowance shall be made for boosting residue gas or other expenses incidental to marketing, except as provided in 30 CFR part 206. In those situations where a processing plant processes gas from more than one lease, only that proportionate share of each lease's residue gas necessary for the operation of the processing plant shall be allowed royalty free.
(c) No royalty is due on residue gas, or any gas plant product resulting from processing gas, which is reinjected into a reservoir within the same lease, unit area, or communitized area, when the reinjection is included in a plan of development or operations and the plan has received BLM or MMS approval for onshore or offshore operations, respectively, until such time as they are finally produced from the reservoir for sale or other disposition off-lease.
[53 FR 1217, Jan. 15, 1988, as amended at 61 FR 5490, Feb. 12, 1996; 64 FR 43513, Aug. 10, 1999]
§ 202.152
Standards for reporting and paying royalties on gas.
(a)(1) If you are responsible for reporting production or royalties, you must:
(i) Report gas volumes and British thermal unit (Btu) heating values, if applicable, under the same degree of water saturation;
(ii) Report gas volumes in units of 1,000 cubic feet (mcf); and
(iii) Report gas volumes and Btu heating value at a standard pressure base of 14.73 pounds per square inch absolute (psia) and a standard temperature base of 60 °F.
(2) The frequency and method of Btu measurement as set forth in the lessee's contract shall be used to determine Btu heating values for reporting purposes. However, the lessee shall measure the Btu value at least semiannually by recognized standard industry testing methods even if the lessee's contract provides for less frequent measurement.
(b)(1) Residue gas and gas plant product volumes shall be reported as specified in this paragraph.
(2) Carbon dioxide (CO2), nitrogen (N2), helium (He), residue gas, and any other gas marketed as a separate product shall be reported by using the same standards specified in paragraph (a) of this section.
(3) Natural gas liquids (NGL) volumes shall be reported in standard U.S. gallons (231 cubic inches) at 60 °F.
(4) Sulfur (S) volumes shall be reported in long tons (2,240 pounds).
[53 FR 1271, Jan. 15, 1988, as amended at 63 FR 26367, May 12, 1998]
Subpart E—Solid Minerals, General [Reserved]

Subpart F—Coal
§ 202.250
Overriding royalty interest.
The regulations governing overriding royalty interests, production payments, or similar interests created under Federal coal leases are in 43 CFR group 3400.
[54 FR 1522, Jan. 13, 1989]
Subpart G—Other Solid Minerals [Reserved]

Subpart H—Geothermal Resources

Source:
56 FR 57275, Nov. 8, 1991, unless otherwise noted.
§ 202.350
Scope and definitions.
(a) This subpart is applicable to all geothermal resources produced from Federal geothermal leases issued pursuant to the Geothermal Steam Act of 1970, as amended (30 U.S.C. 1001 et seq.).
(b) The definitions in 30 CFR 206.351 are applicable to this subpart.
§ 202.351
Royalties on geothermal resources.
(a)(1) Royalties on geothermal resources, including byproducts, or on electricity produced using geothermal resources, will be at the royalty rate(s) specified in the lease, unless the Secretary of the Interior temporarily waives, suspends, or reduces that rate(s). Royalties are determined under 30 CFR part 206, subpart H.
(2) Fees in lieu of royalties on geothermal resources are prescribed in 30 CFR part 206, subpart H.
(3) Except for the amount credited against royalties for in-kind deliveries of electricity to a State or county under § 218.306, you must pay royalties and direct use fees in money.
(b)(1) Except as specified in paragraph (b)(2) of this section, royalties or fees are due on—
(i) All geothermal resources produced from a lease and that are sold or used by the lessee or are reasonably susceptible to sale or use by the lessee, or
(ii) All proceeds derived from the sale of electricity produced using geothermal resources produced from a lease.
(2) For purposes of this subparagraph, the terms “Class I lease,” “Class II lease,” and “Class III lease” have the same meanings prescribed in 30 CFR 206.351.
(i) For Class I leases, MMS will allow free of royalty—
(A) Geothermal resources that are unavoidably lost or reinjected before use on or off the lease, as determined by the Bureau of Land Management (BLM), or that are reasonably necessary to generate plant parasitic electricity or electricity for Federal lease operations; and
(B) A reasonable amount of commercially demineralized water necessary for power plant operations or otherwise used on or for the benefit of the lease.
(ii) For Class II and Class III leases where the lessee uses geothermal resources for commercial production or generation of electricity, or where geothermal resources are sold at arm's length for the commercial production or generation of electricity, MMS will allow free of royalty or direct use fees geothermal resources that are:
(A) Unavoidably lost or reinjected before use on or off the lease, as determined by BLM;
(B) Reasonably necessary for the lessee to generate plant parasitic electricity or electricity for Federal lease operations, as approved by BLM; or
(C) Otherwise used for Federal lease operations related to commercial production or generation of electricity, as approved by BLM.
(iii) For Class II and Class III leases where the lessee uses the geothermal resources for a direct use or in a direct use facility, as defined in 30 CFR 206.351, resources that are used to generate electricity for Federal lease operations or that are otherwise used for Federal lease operations are subject to direct use fees, except for geothermal resources that are unavoidably lost or reinjected before use on or off the lease, as determined by BLM.
(3) Royalties on byproducts are due at the time the recovered byproduct is used, sold, or otherwise finally disposed of. Byproducts produced and added to stockpiles or inventory do not require payment of royalty until the byproducts are sold, utilized, or otherwise finally disposed of. The MMS may ask BLM to increase the lease bond to protect the lessor's interest when BLM determines that stockpiles or inventories become excessive.
(c) If BLM determines that geothermal resources (including byproducts) were avoidably lost or wasted from the lease, or that geothermal resources (including byproducts) were drained from the lease for which compensatory royalty (or compensatory fees in lieu of compensatory royalty) are due, the value of those geothermal resources, or the royalty or fees owed, will be determined under 30 CFR part 206, subpart H.
(d) If a lessee receives insurance or other compensation for unavoidably lost geothermal resources (including byproducts), royalties at the rates specified in the lease (or fees in lieu of royalties) are due on the amount of, or as a result of, that compensation. This paragraph will not apply to compensation through self-insurance.
[72 FR 24458, May 2, 2007]
§ 202.352
Minimum royalty.
In no event shall the lessee's annual royalty payments for any producing lease be less than the minimum royalty established by the lease.
§ 202.353
Measurement standards for reporting and paying royalties and direct use fees.
(a) For geothermal resources used to generate electricity, you must report the quantity on which royalty is due on Form MMS-2014 (Report of Sales and Royalty Remittance) as follows:
(1) For geothermal resources for which royalty is calculated under § 206.352(a), you must report quantities in:
(i) Thousands of pounds to the nearest whole thousand pounds if the contract for the geothermal resources specifies delivery in terms of weight; or
(ii) Millions of Btu to the nearest whole million Btu if the sales contract for the geothermal resources specifies delivery in terms of heat or thermal energy.
(2) For geothermal resources for which royalty is calculated under § 206.352(b), you must report the quantities in kilowatt-hours to the nearest whole kilowatt-hour.
(b) For geothermal resources used in direct use processes, you must report the quantity on which a royalty or direct use fee is due on Form MMS-2014 in:
(1) Millions of Btu to the nearest whole million Btu if valuation is in terms of heat or thermal energy used or displaced;
(2) Millions of gallons to the nearest million gallons of geothermal fluid produced if valuation or fee calculation is in terms of volume;
(3) Millions of pounds to the nearest million pounds of geothermal fluid produced if valuation or fee calculation is in terms of mass; or
(4) Any other measurement unit MMS approves for valuation and reporting purposes.
(c) For byproducts, you must report the quantity on which royalty is due on Form MMS-2014 consistent with MMS-established reporting standards.
(d) For commercially demineralized water, you must report the quantity on which royalty is due on Form MMS-2014 in hundreds of gallons to the nearest hundred gallons.
(e) You need not report the quality of geothermal resources, including byproducts, to MMS. However, you must maintain quality measurements for audit purposes. Quality measurements include, but are not limited to:
(1) Temperatures and chemical analyses for fluid geothermal resources; and
(2) Chemical analyses, weight percent, or other purity measurements for byproducts.
[72 FR 24458, May 2, 2007]
Subpart I—OCS Sulfur [Reserved]

Subpart J—Gas Production From Indian Leases

Source:
64 FR 43514, Aug. 10, 1999, unless otherwise noted.
§ 202.550
How do I determine the royalty due on gas production?
If you produce gas from an Indian lease subject to this subpart, you must determine and pay royalties on gas production as specified in this section.
(a) Royalty rate. You must calculate your royalty using the royalty rate in the lease.
(b) Payment in value or in kind. You must pay royalty in value unless:
(1) The Tribal lessor requires payment in kind; or
(2) You have a lease on allotted lands and MMS requires payment in kind.
(c) Royalty calculation. You must use the following calculations to determine royalty due on the production from or attributable to your lease.
(1) When paid in value, the royalty due is the unit value of production for royalty purposes, determined under 30 CFR part 206, multiplied by the volume of production multiplied by the royalty rate in the lease.
(2) When paid in kind, the royalty due is the volume of production multiplied by the royalty rate.
(d) Reduced royalty rate. The Indian lessor and the Secretary may approve a request for a royalty rate reduction. In your request you must demonstrate economic hardship.
(e) Reporting and paying. You must report and pay royalties as provided in part 218 of this title.
§ 202.551
How do I determine the volume of production for which I must pay royalty if my lease is not in an approved Federal unit or communitization agreement (AFA)?
(a) You are liable for royalty on your entitled share of gas production from your Indian lease, except as provided in §§ 202.555, 202.556, and 202.557.
(b) You and all other persons paying royalties on the lease must report and pay royalties based on your takes. If another person takes some of your entitled share but does not pay the royalties owed, you are liable for those royalties.
(c) You and all other persons paying royalties on the lease may ask MMS for permission to report and pay royalties based on your entitlements. In that event, MMS will provide valuation instructions consistent with this part and part 206 of this title.
§ 202.552
How do I determine how much royalty I must pay if my lease is in an approved Federal unit or communitization agreement (AFA)?
You must pay royalties each month on production allocated to your lease under the terms of an AFA. To determine the volume and the value of your production, you must follow these three steps:
(a) You must determine the volume of your entitled share of production allocated to your lease under the terms of an AFA. This may include production from more than one AFA.
(b) You must value the production you take using 30 CFR part 206. If you take more than your entitled share of production, see § 202.553 for information on how to value this production. If you take less than your entitled share of production, see § 202.554 for information on how to value production you are entitled to but do not take.
§ 202.553
How do I value my production if I take more than my entitled share?
If you take more than your entitled share of production from a lease in an AFA for any month, you must determine the weighted-average value of all of the production that you take using the procedures in 30 CFR part 206, and use that value for your entitled share of production.
§ 202.554
How do I value my production that I do not take if I take less than my entitled share?
If you take none or only part of your entitled production from a lease in an AFA for any month, use this section to value the production that you are entitled to but do not take.
(a) If you take a significant volume of production from your lease during the month, you must determine the weighted average value of the production that you take using 30 CFR part 206, and use that value for the production that you do not take.
(b) If you do not take a significant volume of production from your lease during the month, you must use paragraph (c) or (d) of this section, whichever applies.
(c) In a month where you do not take production or take an insignificant volume, and if you would have used § 206.172(b) to value the production if you had taken it, you must determine the value of production not taken for that month under § 206.172(b) as if you had taken it.
(d) If you take none of your entitled share of production from a lease in an AFA, and if that production cannot be valued under § 206.172(b), then you must determine the value of the production that you do not take using the first of the following methods that applies:
(1) The weighted average of the value of your production (under 30 CFR part 206) in that month from other leases in the same AFA.
(2) The weighted average of the value of your production (under 30 CFR part 206) in that month from other leases in the same field or area.
(3) The weighted average of the value of your production (under 30 CFR part 206) during the previous month for production from leases in the same AFA.
(4) The weighted average of the value of your production (under 30 CFR part 206) during the previous month for production from other leases in the same field or area.
(5) The latest major portion value that you received from MMS calculated under 30 CFR 206.174 for the same MMS-designated area.
(e) You may take less than your entitled share of AFA production for any month, but pay royalties on the full volume of your entitled share under this section. If you do, you will owe no additional royalty for that lease for that month when you later take more than your entitled share to balance your account. The provisions of this paragraph (e) also apply when the other AFA participants pay you money to balance your account.
§ 202.555
What portion of the gas that I produce is subject to royalty?
(a) All gas produced from or allocated to your Indian lease is subject to royalty except the following:
(1) Gas that is unavoidably lost.
(2) Gas that is used on, or for the benefit of, the lease.
(3) Gas that is used off-lease for the benefit of the lease when the Bureau of Land Management (BLM) approves such off-lease use.
(4) Gas used as plant fuel as provided in 30 CFR 206.179(e).
(b) You may use royalty-free only that proportionate share of each lease's production (actual or allocated) necessary to operate the production facility when you use gas for one of the following purposes:
(1) On, or for the benefit of, the lease at a production facility handling production from more than one lease with BLM's approval.
(2) At a production facility handling unitized or communitized production.
(c) If the terms of your lease are inconsistent with this subpart, your lease terms will govern to the extent of that inconsistency.
§ 202.556
How do I determine the value of avoidably lost, wasted, or drained gas?
If BLM determines that a volume of gas was avoidably lost or wasted, or a volume of gas was drained from your Indian lease for which compensatory royalty is due, then you must determine the value of that volume of gas under 30 CFR part 206.
§ 202.557
Must I pay royalty on insurance compensation for unavoidably lost gas?
If you receive insurance compensation for unavoidably lost gas, you must pay royalties on the amount of that compensation. This paragraph does not apply to compensation through self-insurance.
§ 202.558
What standards do I use to report and pay royalties on gas?
(a) You must report gas volumes as follows:
(1) Report gas volumes and Btu heating values, if applicable, under the same degree of water saturation. Report gas volumes and Btu heating value at a standard pressure base of 14.73 psia and a standard temperature of 60 degrees Fahrenheit. Report gas volumes in units of 1,000 cubic feet (Mcf).
(2) You must use the frequency and method of Btu measurement stated in your contract to determine Btu heating values for reporting purposes. However, you must measure the Btu value at least semi-annually by recognized standard industry testing methods even if your contract provides for less frequent measurement.
(b) You must report residue gas and gas plant product volumes as follows:
(1) Report carbon dioxide (CO2), nitrogen (N2), helium (He), residue gas, and any gas marketed as a separate product by using the same standards specified in paragraph (a) of this section.
(2) Report natural gas liquid (NGL) volumes in standard U.S. gallons (231 cubic inches) at 60 degrees F.
(3) Report sulfur (S) volumes in long tons (2,240 pounds).
Pt. 203

PART 203—RELIEF OR REDUCTION IN ROYALTY RATES

Subpart A—General Provisions
Sec.
203.0
What definitions apply to this part?
203.1
What is MMS's authority to grant royalty relief?
203.2
How can I get royalty relief?
203.3
Why must I 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 MMS's authority to collect information?

Subpart B—OCS Oil, Gas, and Sulfur General

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 deep wells?
203.41
If I have a qualified well, what royalty relief will my lease earn?
203.42
To which production do I apply the royalty suspension volume earned from qualified wells on my lease?
203.43
What administrative steps must I take to use the royalty suspension volume?
203.44
If I drill a certified unsuccessful well, what royalty relief will my lease earn?
203.45
To which production do I apply the royalty suspension supplements from drilling one or two certified unsuccessful wells on my lease?
203.46
What administrative steps do I take to obtain and use the royalty suspension supplement?
203.47
Do I keep royalty relief if prices rise significantly?
203.48
May I substitute the deep gas drilling provisions in § 203.0 and §§ 203.40 through 203.47 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 MMS 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 Deep Water Expansion Projects And Pre-Act Deep Water Leases
203.60
Who may apply for deep water royalty relief?
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 MMS take to evaluate my application?
203.66
What happens if MMS 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 MMS 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 MMS approves relief?
203.71
How does MMS 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 MMS reconsider its determination?
203.75
What risk do I run if I request a redetermination?
203.76
When might MMS 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 if prices rise significantly?
203.79
How do I appeal MMS's decisions related to Deep Water Royalty Relief?
203.80
When can I get royalty relief if I am not eligible for end-of-life or deep water royalty relief?

Required Reports
203.81
What supplemental reports do royalty-relief applications require?
203.82
What is MMS'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 deep water 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—Coal
203.250
Advance royalty.
203.251
Reduction in royalty rate or rental.
Subpart G—Other Solid Minerals [Reserved]
Subpart H—Geothermal Resources [Reserved]
Subpart I—OCS Sulfur [Reserved]

Authority:
25 U.S.C. 396 et seq.; 25 U.S.C. 396a et seq.; 25 U.S.C. 2101 et seq.; 30 U.S.C. 181 et seq.; 30 U.S.C. 351 et seq.; 30 U.S.C. 1001 et seq.; 30 U.S.C. 1701 et seq.; 31 U.S.C. 9701; 43 U.S.C. 1301 et seq.; 43 U.S.C. 1331 et seq.; and 43 U.S.C. 1801 et seq.

Subpart A—General Provisions

Source:
63 FR 2616, Jan. 16, 1998, unless otherwise noted.
§ 203.0
What definitions apply to this part?
Authorized field means a field:
(1) Located in a water depth of at least 200 meters and in the Gulf of Mexico (GOM) west of 87 degrees, 30 minutes West longitude;
(2) That includes one or more pre-Act leases; and
(3) From which no current pre-Act lease produced, other than test production, before November 28, 1995.
Certified unsuccessful well means an original well, or a sidetrack with a sidetrack measured depth 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, and before your lease produces gas or oil from a deep well with a perforated interval the top of which is at least 18,000 feet true vertical depth below the datum at mean sea level (TVD SS);
(2) 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;
(3) Fails to meet the producibility requirements of 30 CFR part 250, subpart A, and does not produce gas or oil, or the MMS agrees is not commercially producible; and
(4) For which you have provided the notices and information in § 203.46.
Complete application means an original and two copies of the six reports consisting of the data specified in 30 CFR 203.81, 203.83 and 203.85 through 203.89, along with one set of digital information, which MMS 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. A deep well subsequently re-perforated less than 15,000 feet TVD SS in the same reservoir is still a deep well.
Determination means the binding decision by MMS 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:
(1) Were issued in a sale held after November 28, 2000;
(2) Are located in a water depth of at least 200 meters and in the GOM wholly west of 87 degrees, 30 minutes West longitude; and
(3) Have had no production (other than test production) before the current application for royalty relief.
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 you propose in a Development Operations Coordination Document (DOCD) or a Supplement approved by the Secretary of the Interior after November 28, 1995, that will significantly increase the ultimate recovery of resources from one or more reservoirs that have not produced on a pre-Act lease or a lease issued in a sale held after November 28, 2000. A significant increase does not simply extend recovery from reservoirs already in production. For a pre-Act lease, the expansion project must also involve a substantial capital investment (e.g., fixed-leg platform, subsea template and manifold, tension-leg platform, multiple well project, etc.). For a lease issued after November 28, 2000, the expansion project must involve a new well drilled into a reservoir that has not previously produced. In all cases, all leases in an expansion project must be wholly located in a water depth of at least 200 meters and in the GOM wholly west of 87 degrees, 30 minutes West longitude.
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 DOCD or a Supplement approved by the Secretary of the Interior after November, 28, 1995.
Nonbinding assessment means an opinion by MMS of whether your field could qualify for royalty relief. It is based on your draft application and does not entitle the field to relief.
Original well means a well that is drilled without utilizing an existing wellbore. An original well includes all sidetracks drilled from the original wellbore before the drilling rig moves off the well location. 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 MMS 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 means 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.
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 well means a deep well:
(1) For which drilling begins on or after March 26, 2003;
(2) That produces natural gas (other than test production), including gas associated with oil production, before May 3, 2009; and
(3) For which you have met the requirements prescribed in § 203.43.
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 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 an MMS-approved unit agreement to, the same lease.
Royalty suspension volume 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 part 250, subpart A of this title. 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 part 250, subpart A of this chapter 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.
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.
[63 FR 2616, Jan. 16, 1998, as amended at 67 FR 1872, Jan. 15, 2002; 69 FR 3509, Jan. 26, 2004; 69 FR 24053, Apr. 30, 2004]
§ 203.1
What is MMS'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, authorizes us to grant royalty relief in three 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 Gulf of Mexico (GOM) that are west of 87 degrees, 30 minutes West longitude.
(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);
(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 MMS approved after November 28, 1995.
§ 203.2
How can I get 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, and acquired in a lease sale before November 28, 1995, or after November 28, 2000, and you propose in a DOCD or supplement to expand production significantly. | Are producing and seek to increase ultimate resource recovery from one or more reservoirs not previously or currently producing on the field or lease, not simply extend recovery of reservoirs that already produced. (Expansion project) | A royalty suspension for 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 | Have not produced and can demonstrate that the suspension volume, if any, in your lease is not enough to make development economic (Development project) | 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, 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 elligibility conditions | A royalty modification in size, duration, or form that makes your lease or project economic. (See § 203.80.)
[67 FR 1872, Jan. 15, 2002]
§ 203.3
Why must I pay a fee to request royalty relief?
(a) 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. 104-133, 110 Stat. 1321, April 26, 1996) authorize us to collect these fees.
(b) We will specify the necessary fees for each of the types of royalty-relief applications and possible MMS 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.
§ 203.4
How do the provisions in this part apply to different types of leases and projects?
The tables in this section summarize the similar application and approval provisions for the discretionary end-of-life and deep water royalty relief programs in §§ 203.50 to 203.91. Because royalty relief for deep gas on leases not subject to deep water royalty relief, as provided for under §§ 203.40 to 203.48, does not involve an application, its provisions do not parallel the other two royalty relief programs and are not summarized in this section.
(a) We require the information elements indicated by an X in the following table and described in §§ 203.51, 203.62, and 203.81 through 203.89 for applications for royalty relief.
Information elements | End-of-life lease | Deep water | Expansion project | Pre-act lease | Development project
(1) Administrative information report | X | X | X | X
(2) Net revenue and relief justification report (prescribed format) | X
(3) Economic viability and relief justification report (Royalty Suspension Viability Program (RSVP) model inputs justified with Geological and Geophysical (G&G), Engineering, Production, & Cost reports) | | X | X | X
(4) G&G report | | X | X | X
(5) Engineering report | | X | X | X
(6) Production report | | X | X | X
(7) Deep water cost report | | X | X | X
(b) We require the confirmation elements indicated by an X in the following table and described in §§ 203.70, 203.81 and 203.90 through 203.91 to retain royalty relief.
Confirmation elements | End-of-life lease | Deep water | Expansion project | Pre-act lease | Development project
(1) Fabricator's confirmation report | | X | X | X
(2) Post-production development report approved by an independent certified public accountant (CPA) | | X | X | X
(c) The following table indicates by an X, and §§ 203.50, 203.52, 203.60 and 203.67 describe, the prerequisites for our approval of your royalty relief application.
Approval conditions | End-of-life lease | Deep water | Expansion | Pre-act lease | Development project
(1) At least 12 of the last 15 months have the required level of production | X
(2) Already producing | X
(3)A producible well into a reservoir that has not produced before | | X | X | X
(4) Royalties for qualifying months exceed 75% of net revenue (NR) | X
(5) Substantial investment on a pre-Act lease (e.g., platform, subsea template)
(6) Determined to be economic only with relief | | X | X | X
(d) The following table indicates by an X, and §§ 203.52 and 203.74 through 203.75 describe, the prerequisites for a redetermination of our royalty relief decision.
Redetermination conditions | End-of-Life lease | Deep water | Expansion project | Pre-act lease | Development project
(1) After 12 months under current rate, criteria same as for approval | X
(2) For material change in geologic data, prices, costs, or available technology | | X | X | X
(e) The following table indicates by an X, and §§ 203.53 and 203.69 describe, the characteristics of approved royalty relief.
Relief rate and volume, subject to certain conditions | End-of-life lease | Deep water | Expansion project | Pre-act lease | Development project
(1) One-half pre-application effective lease rate on the qualifying amount, 1.5 times pre-application effective lease rate on additional production up to twice the qualifying amount, and the pre-application effective lease rate for any larger volumes | X
(2) Qualifying amount is the average monthly production for 12 qualifying months | X
(3) Zero royalty rate on the suspension volume and the original lease rate on additional production | | X | X | X
(4) Suspension volume is at least 17.5, 52.5 or 87.5 million barrels of oil equivalent (MMBOE) | | | X
(5) Suspension volume is at least the minimum set in the Notice of Sale, the lease, or the regulations | | X | | X
(6) Amount needed to become economic | | X | X | X
(f) The following table indicates by an X, and §§ 203.54 and 203.78 describe, circumstances under which we discontinue your royalty relief.
Full royalty resumes when | End-of-life lease | Deep water | Expansion project | Pre-act lease | Development project
(1) Average NYMEX price for last 12 months is at least 25 percent above the average for the qualifying months | X
(2) Average NYMEX price for last calendar year exceeds $28/bbl or $3.50/mcf, escalated by the gross domestic product (GDP) deflator since 1994 | | X | X
(3) Average prices for designated periods exceed levels we specify in the Notice of Sale or the lease | | X | | X
(g) The following table indicates by an X, and §§ 203.55 and 203.76 through 203.77 describe, circumstances under which we end or reduce royalty relief.
Relief withdrawn or reduced | End-of-life lease | Deep water | Expansion project | Pre-act lease | Development project
(1) If recipient requests | X | X | X | X
(2) Lease royalty rate is at the effective rate for 12 consecutive months | X
(3) Conditions occur that we specified in the approval letter in individual cases | X
(4) Recipient does not submit post-production report that compares expected to actual costs | | X | X | X
(5) Recipient changes development system | | X | X | X
(6) Recipient excessively delays starting fabrication | | X | X | X
(7) Recipient spends less than 80 percent of proposed pre-production costs prior to start of production | | X | X | X
(8) Amount of relief volume is produced | | X | X | X
[67 FR 1873, Jan. 15, 2002, as amended at 69 FR 3509, Jan. 26, 2004]
§ 203.5
What is MMS's authority to collect information?
The Paperwork Reduction Act of 1995 (PRA) requires us to inform you that MMS 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. OMB approved the information collection requirements in this part 203 under 44 U.S.C. 3501 et seq. in two actions. The information collection requirements in §§ 203.50 through 203.91 are approved under OMB control number 1010-0071, and those in §§ 203.40 through 203.48 are approved under 1010-0153.
[69 FR 3509, Jan. 26, 2004]

Subpart B—OCS Oil, Gas, and Sulfur General

Source:
63 FR 2618, Jan. 16, 1998, unless otherwise noted.

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

Source:
69 FR 3510, Jan. 26, 2004, unless otherwise noted.
§ 203.40
Which leases are eligible for royalty relief as a result of drilling deep wells?
Your lease may receive a royalty suspension volume under §§ 203.41 through 203.43, and may receive a royalty suspension supplement under §§ 203.44 through 203.46, if it:
(a) Was:
(1) In existence on January 1, 2001;
(2) Issued in a lease sale held after January 1, 2001, and before April 1, 2004, and either the lessee has exercised the option provided for in § 203.48 or the lease is located partly in water less than 200 meters deep and no deep water royalty relief provisions in statutes or lease terms apply to the lease; or
(3) Issued in a lease sale held on or after April 1, 2004, and either the lease terms provide for royalty relief under §§ 203.41 through 203.47 of this part or the lease is located partly in water less than 200 meters deep and no deep water royalty relief provisions in statutes or lease terms apply to the lease;
(b) Is located:
(1) In the GOM, wholly west of 87 degrees, 30 minutes West longitude;
(2) Entirely in water less than 200 meters deep, or partly in water less than 200 meters deep and no deep-water royalty relief provisions in statutes or lease terms apply to the lease; and
(c) Has not produced gas or oil from a deep well with a perforated interval the top of which is 18,000 feet TVD SS or deeper that commenced drilling before March 26, 2003.
[69 FR 3510, Jan. 26, 2004, as amended at 70 FR 22252, Apr. 29, 2005]
§ 203.41
If I have a qualified well, what royalty relief will my lease earn?
(a) This paragraph and paragraph (b) of this section apply if your lease has not produced gas or oil from a deep well that commenced drilling before March 26, 2003. Subject to the administrative requirements of § 203.43, the provisions of § 203.44(d), and the price conditions in § 203.47, you earn a royalty suspension volume shown in the following table in billions of cubic feet (BCF) or in thousands of cubic feet (MCF) applicable to gas production as prescribed in § 203.42:
If you have a qualified well that is . . . | Then you earn a royalty suspension volume on this amount of gas production, as prescribed in this section and § 203.42:
(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 18,000 feet TVD SS or deeper | 25 BCF.
(4) 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 25 BCF.
(b) We will suspend royalties on gas volumes produced on or after May 3, 2004, reported on the Oil and Gas Operations Report, Part A (OGOR-A) for your lease under 30 CFR part 210, Subpart C—Production Reports—Oil and Gas, as and to the extent prescribed in § 203.42.

Example 1.
If you have a qualified well that is an original well with a perforated interval the top of which is 16,000 feet TVD SS, you earn a royalty suspension volume of 15 BCF of gas production from qualified wells on your lease, as prescribed in § 203.42. However, if the top of the perforated interval is 18,500 feet TVD SS, the royalty suspension volume is 25 BCF.

Example 2.
If you have a qualified well that is a sidetrack with a perforated interval the top of which is 16,000 feet TVD SS, that has a sidetrack measured depth of 6,789 feet, we round the distance to 6,800 feet and you earn a royalty suspension volume of 8.08 BCF of gas production from qualified wells on your lease, as prescribed in § 203.42.

Example 3.
If you have a qualified well that is a sidetrack with a perforated interval the top of which is 16,000 feet TVD SS, that has a sidetrack measured depth of 19,500 feet, you earn a royalty suspension volume of 15 BCF of gas production from qualified wells on your lease, as prescribed in § 203.42, even though 4 BCF plus 600 MCF per foot of sidetrack measured depth equals 15.7 BCF.
(c) This paragraph and paragraph (d) of this section apply if 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 (regardless of whether drilling began before or after March 26, 2003), and you subsequently have a qualified well on your lease with a perforated interval the top of which is 18,000 feet TVD or deeper. Subject to the administrative requirements of § 203.43, the provisions of § 203.44(d), and the price conditions in § 203.47, you earn a royalty suspension volume specified in the following table, applicable to gas production as prescribed in § 203.42. This royalty suspension volume is in addition to any royalty suspension volume your lease already may have earned, if any, as a result of a qualified well with a perforated interval the top of which is from 15,000 to less than 18,000 feet TVD SS.
If 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, and you subsequently have a qualified well that is . . . | Then, you earn a royalty suspension volume on this amount of gas production, as prescribed in this section and § 203.42
(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) We will suspend royalties on gas volumes produced on or after May 3, 2004, reported on the Oil and Gas Operations Report, Part A (OGOR-A) for your lease under 30 CFR part 210, Subpart C—Production Reports—Oil and Gas, as and to the extent prescribed in § 203.42.

Example 1.
If you have drilled and produced a well with a perforated interval the top of which is 16,000 feet TVD SS before March 26, 2003 (and therefore, it is not a qualified well and has earned no royalty suspension volume) and later drill:
(i) A well with a perforated interval the top of which is 17,000 feet TVD SS, you earn no royalty suspension volume.
(ii) A qualified well that is an original well with a perforated interval the top of which is 19,000 feet TVD SS, you earn a royalty suspension volume of 10 BCF of gas production from qualified wells on your lease, as prescribed in § 203.42.
(iii) A qualified 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, you earn a royalty suspension volume of 8.2 BCF of gas production from qualified wells on your lease, as prescribed in § 203.42.

Example 2.
If you have a qualified well (i.e., drilled after March 26, 2003) 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 royalty suspension volume for your lease from 15 BCF to 25 BCF, as prescribed in § 203.42.

Example 3.
If you have a qualified well (i.e., drilled after March 26, 2003) that is a sidetrack with a perforated interval the top of which is 16,000 feet TVD SS, that has 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, that has a sidetrack measured depth of 8,000 feet, we increase the total royalty suspension volume for your lease from 6.4 BCF to 15.2 BCF, as prescribed in § 203.42. The difference of 8.8 BCF represents the royalty suspension volume earned by the second sidetrack.
(e) After your lease has produced gas or oil from a deep well with a perforated interval the top of which is 18,000 feet TVD SS or deeper, your lease cannot earn a royalty suspension volume as a result of drilling any subsequent qualified wells.
(f) The royalty suspension volume determined under this section for the first qualified well on your lease (whether an original well or a sidetrack) establishes the total royalty suspension volume available for that drilling depth interval on your lease, regardless of the number of subsequent qualified wells you drill to that depth interval.

Example to paragraph (f):
If your first qualified well is a sidetrack with a perforated interval the top of which is 16,000 feet TVD SS and earns a royalty suspension volume of 12.5 BCF, and you later drill a qualified original well to 17,000 feet TVD SS, the royalty suspension volume for your lease remains at 12.5 BCF and does not increase to 15 BCF. However, under paragraph (b) of this section, if you subsequently drill a qualified well to another depth interval 18,000 feet or greater TVD SS, you may earn an additional royalty suspension volume.
(g) If a qualified well on your lease is within a unitized portion of your lease, the royalty suspension volume earned by that well under this section applies only to your lease and not to other leases within the unit.
(h) If your qualified 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 royalty suspension volume. However, if the perforated interval crosses a lease line, the lease where the surface of the well is located earns the royalty suspension volume.
(i) Any royalty suspension volume earned under this section is in addition to any royalty suspension supplement for your lease under § 203.44 that results from a different wellbore.
(j) If your lease earns a royalty suspension volume under this section and later produces from a deep well that is not a qualified well, the royalty suspension volume is not forfeited or terminated. However, you may not apply the royalty suspension volume under this section to production from the deep well that is not a qualified well, even if it begins producing after your first qualified well.
(k) You owe minimum royalties or rentals in accordance with your lease terms notwithstanding any royalty suspension volumes allowed under paragraphs (a) and (b) of this section.
[69 FR 3510, Jan. 26, 2004, as amended at 69 FR 24053, Apr. 30, 2004; 73 FR 15889, Mar. 26, 2008]
§ 203.42
To which production do I apply the royalty suspension volume earned from qualified wells on my lease?
(a) This paragraph applies to any lease that is not within an MMS-approved unit. Subject to the requirements of §§ 203.40, 203.41, 203.43, 203.44, and 203.47, you must apply the royalty suspension volumes prescribed in § 203.41 to the earliest gas production:
(1) Occurring on and after the later of May 3, 2004, or the date that the first qualified well that earns your lease the royalty suspension volume begins production (other than test production);
(2) From all qualified wells, regardless of their depth, on your lease for which you have met the requirements in § 203.43, up to the aggregate royalty suspension volume earned by your lease.

Example to paragraph (a):
You began drilling an original well that was a qualified well with a perforated interval the top of which is 18,200 feet TVD SS on May 1, 2003 and it began producing on September 1, 2003. You subsequently drilled two more original wells that are qualified wells with a perforated interval the tops of which are 16,600 feet TVD SS. The first well earned a royalty suspension volume of 25 BCF. You must apply the royalty suspension volume each month beginning on March 1, 2004 to production from all three wells until the 25 BCF royalty suspension volume is fully utilized.
(b) This paragraph applies to any lease all or part of which is within an MMS-approved unit. If your lease has a qualified well, a share of the production from all the qualified wells in the unit participating area will be allocated to your lease each month according to the participating area percentages. Subject to the requirements of §§ 203.40, 203.41, 203.43, 203.44, and 203.47, you must apply the royalty suspension volume to the earliest gas production occurring on and after the later of May 3, 2004, or the date that the first qualified well that earns your lease the royalty suspension volume begins production (other than test production):
(1) From all qualified wells on the non-unitized area of your lease and
(2) Allocated to your lease from qualified wells on unitized areas of your lease and other leases in the unit under an MMS-approved unit agreement. That allocated share does not increase the royalty suspension volume 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 to paragraph (b):
The east half of your lease A is unitized with all of lease B. There is one qualified well on the non-unitized portion of lease A, one qualified well on the unitized portion of lease A and a qualified well on lease B. The participating area percentages allocate 32 percent of production from both of the unit qualified wells to lease A and 68 percent to lease B. If the non-unitized qualified well on lease A produces 12,000 MCF and the unitized qualified well on lease A produces 15,000 MCF, and the qualified well on lease B produces 10,000 MCF, then the production volume from and allocated to lease A to which the lease A royalty suspension volume applies is 20,000 MCF [12,000 + (15,000 + 10,000)(32 percent)]. The production volume allocated to lease B to which the lease B royalty suspension volume applies is 17,000 MCF [(15,000 + 10,000)(68 percent)].
(c) Unused royalty suspension volume transfers to a successor lessee and expires with the lease.
(d) You may not apply the royalty suspension volume allowed under § 203.41:
(1) 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;
(2) To production from a deep well that commenced drilling before March 26, 2003; or
(3) To production from a deep well on any other lease, except as provided in paragraph (b) of this section.
(e) 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 royalty suspension volume allowed under § 203.41. For the month in which cumulative production reaches this royalty suspension volume, you owe royalties on the portion of gas production that exceeds the royalty suspension volume remaining at the beginning of that month.
(f) No royalty suspension volume may be applied to any liquid hydrocarbon (oil and condensate) volumes.
[69 FR 3510, Jan. 26, 2004, as amended at 69 FR 24054, Apr. 30, 2004]
§ 203.43
What administrative steps must I take to use the royalty suspension volume?
(a) You must notify, in writing, the MMS Regional Supervisor for Production and Development of your intent to begin drilling operations on all 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 MMS 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 MMS Regional Supervisor for Production and Development has determined are necessary under 30 CFR part 250, subpart L.
(d) If you produced from a qualified well before May 3, 2004, you must provide the information in paragraph (b) of this section no later than August 3, 2004.
(e) If you cannot produce from a well that otherwise meets the criteria for a qualified well before May 3, 2009, the MMS 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, provided you demonstrate that:
(1) The delay occurred after reaching total depth in your well;
(2) Production (other than test production) was expected to begin before March 1, 2009; and
(3) The delay in beginning production is for reasons beyond your control, including but not limited to adverse weather and unavoidable accidents.
[69 FR 3510, Jan. 26, 2004, as amended at 69 FR 24054, Apr. 30, 2004]
§ 203.44
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 § 203.46 and subject to the price conditions in § 203.47, you earn a royalty suspension supplement shown in the following table (in billions of cubic feet of gas equivalent (BCFE) or in thousands of cubic feet of gas equivalent (MCFE)) applicable to oil and gas production as prescribed in § 203.45:
If you have a certified unsuccessful well that is . . . | Then, you earn a royalty suspension supplement on this volume of oil and gas production as prescribed in this section and § 203.45:
(1) An original well and your lease has not produced gas or oil from a deep well | 5 BCFE.
(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 | 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) We will suspend royalties on oil and gas volumes produced on or after May 3, 2004, reported on the Oil and Gas Operations Report, Part A (OGOR-A) for your lease under 30 CFR part 210, Subpart C—Production Reports—Oil and Gas, as and to the extent prescribed in § 203.45.

Example 1.
If you drill a certified unsuccessful well that is an original well to a target 19,000 feet TVD SS, you earn a royalty suspension supplement of 5 BCFE of gas and oil production if your lease has not previously produced from a deep well, or you earn a royalty suspension supplement 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 § 203.45.

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, we round the distance to 12,500 feet and you earn a royalty suspension supplement 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 a royalty suspension supplement as a certified unsuccessful well later produces from a perforated interval the top of which is 15,000 feet TVD SS or deeper before May 3, 2009, it will become a qualified well 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.
[69 FR 3510, Jan. 26, 2004, as amended at 69 FR 24054, Apr. 30, 2004; 72 FR 25198, May 4, 2007; 73 FR 15890, Mar. 26, 2008]
§ 203.45
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, 203.42, 203.44, 203.46 and 203.47, you must apply royalty suspension supplements in § 203.44 to the earliest oil and gas production:
(1) Occurring on and after the day you file the information under § 203.46(b),
(2) From, or allocated under an MMS-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 royalty suspension supplement allowed under § 203.44, your royalty suspension supplement applies to the earliest subsequent production of gas and oil from, or allocated under an MMS-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 royalty suspension supplement allowed under § 203.44 to production from any other lease, except for production allocated to your lease from an MMS-approved unit agreement. If your certified unsuccessful well is on a lease subject to an MMS-approved unit agreement, the lessees of other leases in the unit may not apply any portion of the royalty suspension supplement 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 an MMS-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 suspension supplement remaining at the beginning of that month.
§ 203.46
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 MMS 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 MMS Regional Supervisor for Production and Development within 60 days after reaching the total depth in your well:
(1) Information that allows MMS 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 250, subpart A; or
(ii) Well log, well test, seismic, and economic data, if your well does meet the producibility requirements of 30 CFR part 250, subpart A; and
(2) Information that allows MMS 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 or after March 26, 2003, and finished it before May 3, 2004, provide the information in paragraph (b) of this section no later than August 3, 2004.
[69 FR 3510, Jan. 26, 2004, as amended at 69 FR 24054, Apr. 30, 2004]
§ 203.47
Do I keep royalty relief if prices rise significantly?
(a) You must pay royalties on all gas and oil production for which royalty suspension volume or royalty suspension supplement otherwise would be allowed under §§ 203.40 through 203.46 for any calendar year when the average daily closing NYMEX natural gas price exceeds the threshold of $9.34 per MMBtu, adjusted annually after year 2004 for inflation. The threshold price for any calendar year after 2004 is found 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.
(b) You must pay any royalty due under this paragraph, plus late payment interest from the end of the month after the month of production until the date of payment under 30 CFR 218.54, no later than 90 days after the end of the calendar year for which you owe royalty.
(c) Production volumes on which you must pay royalty under this section count as part of your royalty suspension volumes and royalty suspension supplements.
§ 203.48
May I substitute the deep gas drilling provisions in § 203.0 and §§ 203.40 through 203.47 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 203.47 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 MMS 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 203.47.
(d) Exercising the option under paragraph (a) of this section is irrevocable. If you do not exercise this option, then the terms of your lease apply.

Royalty Relief for End-of-life Leases
§ 203.50
Who may apply for end-of-life royalty relief?
You may apply for royalty relief in two situations.
(a) Your end-of-life lease (as defined in § 203.2) is an oil and gas lease and has average daily production of at least 100 barrels of oil equivalent (BOE) per month (as calculated in § 203.73) in at least 12 of the past 15 months. The most recent of these 12 months are considered the qualifying months. These 12 months should reflect the basic operation you intend to use until your resources are depleted. If you changed your operation significantly (e.g., begin re-injecting rather than recovering gas) during the qualifying months, or if you do so while we are processing your application, we may defer action on your application until you revise it to show the new circumstances.
(b) Your end-of-life lease is other than an oil and gas lease (e.g., sulphur) and has production in at least 12 of the past 15 months. The most recent of these 12 months are considered the qualifying months.
[63 FR 2618, Jan. 16, 1998, as amended at 63 FR 57249, Oct. 27, 1998]
§ 203.51
How do I apply for end-of-life royalty relief?
You must submit a complete application and the required fee to the appropriate MMS Regional Director. Your MMS regional office will provide specific guidance on the report formats. A complete application for relief includes:
(a) An administrative information report (specified in § 203.83) and
(b) A net revenue and relief justification report (specified in § 203.84).
§ 203.52
What criteria must I meet to get relief?
(a) To qualify for relief, you must demonstrate that the sum of royalty payments over the 12 qualifying months exceeds 75 percent of the sum of net revenues (before-royalty revenues minus allowable costs, as defined in § 203.84).
(b) To re-qualify for relief, e.g., either applying for additional relief on top of relief already granted, or applying for relief sometime after your earlier agreement terminated, you must demonstrate that:
(1) You have met the criterion listed in paragraph (a) of this section, and
(2) The 12 required qualifying months of operation have occurred under the current royalty arrangement.
§ 203.53
What relief will MMS grant?
(a) If we approve your application and you meet certain conditions, we will reduce the pre-application effective royalty rate by one-half on production up to the relief volume amount. If you produce more than the relief volume amount:
(1) We will impose a royalty rate equal to 1.5 times the effective royalty rate on your additional production up to twice the relief volume amount; and
(2) We will impose a royalty rate equal to the effective rate on all production greater than twice the relief volume amount.
(b) Regardless of the level of production or prices (see § 203.54), royalty payments due under end-of-life relief will not exceed the royalty obligations that would have been due at the effective royalty rate.
(1) The effective royalty rate is the average lease rate paid on production during the 12 qualifying months.
(2) The relief volume amount is the average monthly BOE production for the 12 qualifying months.
§ 203.54
How does my relief arrangement for an oil and gas lease operate if prices rise sharply?
In those months when your current reference price rises by at least 25 percent above your base reference price, you must pay the effective royalty rate on all monthly production.
(a) Your current reference price is a weighted average of daily closing prices on the NYMEX for light sweet crude oil and natural gas over the most recent full 12 calendar months;
(b) Your base reference price is a weighted average of daily closing prices on the NYMEX for light sweet crude oil and natural gas during the qualifying months; and
(c) Your weighting factors are the proportions of your total production volume (in BOE) provided by oil and gas during the qualifying months.
§ 203.55
Under what conditions can my end-of-life royalty relief arrangement for an oil and gas lease be ended?
(a) If you have an end-of-life royalty relief arrangement, you may renounce it at any time. The lease rate will return to the effective rate during the qualifying period in the first full month following our receipt of your renouncement of the relief arrangement.
(b) If you pay the effective lease rate for 12 consecutive months, we will terminate your relief. The lease rate will return to the effective rate in the first full month following this termination.
(c) We may stipulate in the letter of approval for individual cases certain events that would cause us to terminate relief because they are inconsistent with an end-of-life situation.
§ 203.56
Does relief transfer when a lease is assigned?
Yes. Royalty relief is based on the lease circumstances, not ownership. It transfers upon lease assignment.

Royalty Relief For Deep Water Expansion Projects And Pre-Act Deep Water Leases
§ 203.60
Who may apply for deep water royalty relief?
You may apply for royalty relief under §§ 203.61(b) and 203.62 if:
(a) You are a lessee of a lease in water at least 200 meters deep in the GOM and lying wholly west of 87 degrees, 30 minutes West longitude;
(b) We have assigned your pre-Act lease to a field (as defined in § 203.0); and
(c) You either:
(1) Hold a pre-Act lease on an authorized field (as defined in § 203.0) or
(2) Propose an expansion project (as defined in § 203.0) or
(3) Propose a development project (as defined in § 203.0).
[67 FR 1875, Jan. 15, 2002]
§ 203.61
How do I assess my chances for getting relief?
You may ask for a nonbinding assessment (a formal opinion on whether a field would qualify for royalty relief) before turning in your first complete application on an authorized field. This field must have a qualifying well under 30 CFR part 250, 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 MMS 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.

Effective Date Note:
At 63 FR 2619, Jan. 16, 1998, § 203.61 was revised. This section contains information collection and recordkeeping requirements and will not become effective until approval has been given by the Office of Management and Budget.
§ 203.62
How do I apply for relief?
You must send a complete application and the required fee to the MMS Regional Director for the GOM.
(a) Your application for deep water royalty relief must include an original and two copies (one set of digital information) of:
(1) Administrative information report;
(2) Deep water economic viability and relief justification report;
(3) G&G report;
(4) Engineering report;
(5) Production report; and
(6) Deep water cost report.
(b) Section 203.82 explains why we are authorized to require these reports.
(c) Sections 203.81, 203.83, and 203.85 through 203.89 describe what these reports must include. The MMS regional office for the GOM will guide you on the format for the required reports, and we encourage you to contact this office prior to preparing your application for this guidance.
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1875, Jan. 15, 2002]
§ 203.63
Does my application have to include all leases in the field?
(a) For authorized fields, we will accept only one joint application for all leases that are part of the designated field on the date of application, except as provided in paragraph (a)(3) of this section and § 203.64. However, we will evaluate all acreage that may eventually become part of the authorized field. Therefore, if you have any other leases that you believe may eventually be part of the authorized field, you must submit data for these leases according to § 203.81.
(1) The Regional Director maintains a Field Names Master List with updates of all leases in each designated field.
(2) To avoid sharing proprietary data with other lessees on the field, you may submit your proprietary G&G report separately from the rest of your application. Your application is not complete until we receive all the required information for each lease on the field. We will not disclose proprietary data when explaining our assumptions and reasons for our determinations under § 203.67.
(3) We will not require a joint application if you show good cause and honest effort to get all lessees in the field to participate. If you must exclude a lease from your application because its lessee will not participate, that lease is ineligible for the royalty relief for the designated field.
(b) If your application seeks only relief for a development project or an expansion project, your application does not have to include all leases in the field.
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1875, Jan. 15, 2002]
§ 203.64
How many applications may I file on a field or a development project?
You may file one complete application for royalty relief during the life of the field or for a development project or an expansion project designed to produce a reservoir or set of reservoirs. However, you may send another application if:
(a) You are eligible to apply for a redetermination under § 203.74;
(b) You apply for royalty relief for an expansion project;
(c) You withdraw the application before we make a determination; or
(d) You apply for end-of-life royalty relief.
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1875, Jan. 15, 2002]
§ 203.65
How long will MMS 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—
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.
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.
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.
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1875, Jan. 15, 2002]
§ 203.66
What happens if MMS does not act in the time allowed?
If we do not act within the timeframes established under § 203.65, you get royalty relief according to the following table.
If you apply for royalty relief for | And we do not decide within the time specified | As long as you
(a) An authorized field | You get the minimum suspension volumes specified in § 203.69 | Abide by §§ 203.70 and 203.76.
(b) An expansion project | You get a royalty suspension for the first year of production | Abide by §§ 203.70 and 203.76.
(c) A development project | You get a royalty suspension for initial production for the number of months that a decision is delayed beyond the stipulated timeframes set by § 203.65, plus all the royalty suspension volume for which you qualify | Abide by §§ 203.70 and 203.76.
[67 FR 1875, Jan. 15, 2002]
§ 203.67
What economic criteria must I meet to get royalty relief on an authorized field or project?
We will not approve applications if we determine that royalty relief cannot make the field, development project, or expansion project economically viable. Your field or project must be uneconomic while you are paying royalties and must become economic with royalty relief.
[67 FR 1876, Jan. 15, 2002]
§ 203.68
What pre-application costs will MMS 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.
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1876, Jan. 15, 2002]
§ 203.69
If my application is approved, what royalty relief will I receive?
If we approve your application, subject to certain conditions, we will not collect royalties on a specified suspension volume for your field, development project, or expansion project. Suspension volumes include volumes allocated to a lease under an approved unit agreement, but exclude any volumes of production that are not normally royalty-bearing under the lease or the regulations of this chapter (e.g., fuel gas).
(a) For authorized fields, the minimum royalty-suspension volumes are:
(1) 17.5 million barrels of oil equivalent (MMBOE) for fields in 200 to 400 meters of water;
(2) 52.5 MMBOE for fields in 400 to 800 meters of water; and
(3) 87.5 MMBOE for fields in more than 800 meters of water.
(b) For development projects, any relief we grant applies only to project wells and replaces the royalty suspension volume with which we issued your lease. If your project is economic given the royalty suspension volume with which we issued your lease, we will reject the application. Otherwise, the minimum royalty suspension volumes are as shown in the following table:
For | The minimum royalty suspension volume is | Plus
(1) RS leases | 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 we 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 we based approval of your application from all reservoirs included in the project.
(2) Other deep water 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 we based approval of your application from all reservoirs included in the project. |
(c) If your application includes pre-Act or eligible 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 “Field Names Master List” documents and updates in effect at the time your application is deemed complete. These publications are available from the MMS Regional Office for the GOM.
(d) 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.
(e) 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.
(f) 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.
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1876, Jan. 15, 2002]
§ 203.70
What information must I provide after MMS 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 MMS regional office for the GOM will prescribe the formats.
Required report | When due to MMS | Due date extensions
(a) Fabricator's confirmation report | Within 18 months after approval of relief | MMS 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, MMS Regional Director for the GOM may extend due date up to 30 days.
[67 FR 1876, Jan. 15, 2002]
§ 203.71
How does MMS 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 field after we approve relief | We will not change your field's royalty suspension volume | The assigned lease(s) may share in any remaining royalty relief.
(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(s) that you operate to your field while we are evaluating your application | We will change your field's minimum suspension volume if the assigned lease is a pre-Act or eligible lease entitled to a larger minimum or automatic suspension volume | (i) You toll the time period for evaluation until 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 do not agree to toll, we will have to reject your application due to incomplete information. But, an eligible lease we assigned to the field kept its automatic suspension volume.
| (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 post-November 2000 deep water lease to another field | The past production from the well counts toward the royalty suspension volume of the field to which we assigned the well | The past production from that well will not count toward any royalty suspension volume granted to the field from which we reassigned it.
(b) If your authorized field has a royalty suspension volume established under § 260.111 of this title (i.e., a field with a pre-Act lease where an eligible lease starts production first), we will suspend payment of royalties on production from all eligible leases in the field until their cumulative production equals the established volume. The following conditions also apply:
If . . . | Then . . . | And . . .
(1) We assign another eligible lease to your field | Your field's royalty suspension volume does not change | The assigned lease may share in any remaining royalty relief.
(2) We assign an RS lease to your field | Your field's royalty suspension volume does not change | The assigned lease gets only the volume suspension with which we issued it, and its production volume counts against the field's royalty suspension volume.
(3) We assign a pre-Act lease or a lease issued after November 2000 without royalty suspension to your field | Your field's royalty suspension volume does not change | We assign lease shares none of the volume suspension, and its production does not count as part of the suspension volume.
(4) A pre-Act or post-November 2000 deep water lease applies (along with the other leases in the field) and qualifies (subject to any pre-existing suspension volumes) for royalty relief under §§ 203.67 and 203.69 | Your field's royalty suspension volume may increase or stay the same, but will not diminish | (i) All leases in the field share the royalty suspension volume if we approve the application; or (ii) The eligible or RS leases in the field keep their respective volumes if we reject the application.
(c) 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.
(d) 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.
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1877, Jan. 15, 2002]
§ 203.72
Can my lease receive more than one suspension volume?
Yes. You may apply for royalty relief that involves more than one suspension volume under § 203.62 in two circumstances.
(a) Each field that includes your lease may receive a separate 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.
§ 203.73
How do suspension volumes apply to natural gas?
You must measure natural gas production under the royalty-suspension volume as follows: 5.62 thousand cubic feet of natural gas, measured in accordance with 30 CFR part 250, subpart L, equals one barrel of oil equivalent.
§ 203.74
When will MMS 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 approval or you relinquished royalty relief. “Significant” means that the new G&G data:
(1) Results from drilling new wells or getting new three-dimensional seismic data and information (but not reinterpreting old data);
(2) Did not exist at the time of the earlier application; and
(3) Changes your estimates of gross resource size, quality, or projected flow rates enough to materially affect the results of our earlier determination.
(b) You demonstrate in your new application that the technology that most efficiently develops this field or lease was not considered or deemed feasible in the original application. Your newly proposed technology must improve the profitability, under equivalent market conditions, of the field or lease relative to the development system proposed in the prior application.
(c) Your current reference price decreases by more than 25 percent from your base reference price as calculated under this paragraph.
(1) Your current reference price is a weighted-average of daily closing prices on the NYMEX for light sweet crude oil and natural gas over the most recent full 12 calendar months;
(2) Your base reference price is a weighted average of daily closing prices on the NYMEX for light sweet crude oil and natural gas for the full 12 calendar months preceding the date of your most recently approved application for this royalty relief; and
(3) The weighting factors are the proportions of the total production volume (in BOE) for oil and gas associated with the most likely scenario (identified in §§ 203.85 and 203.88) from your most recently approved application for this royalty relief.
(d) Before starting to build your development and production system, you have revised your estimated development costs, and they are more than 120 percent of the eligible development costs associated with the most likely scenario from your most recently approved application for this royalty relief.
[63 FR 2618, Jan. 16, 1998; 63 FR 24747, May 5, 1998, as amended at 67 FR 1878, Jan. 15, 2002]
§ 203.75
What risk do I run if I request a redetermination?
If you request a redetermination after we have granted you a suspension volume, you could lose some or all of the previously granted relief. This can happen because you must file a new complete application and pay the required fee, as discussed in § 203.62. We will evaluate your application under § 203.67 using the conditions prevailing at the time of your redetermination request. In our evaluation, we may find that you should receive a larger, equivalent, smaller, or no suspension volume. This means we could find that you do not qualify for the amount of relief previously granted or for any relief at all.
§ 203.76
When might MMS 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 within18 months of the date we approved your application, unless the MMS 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 § 218.54 of this chapter on all volumes for which you used the royalty suspension. You also may be subject to penalties under other provisions of law.
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1878, Jan. 15, 2002]
§ 203.77
May I voluntarily give up relief if conditions change?
Yes, by sending a letter to that effect to the MMS Regional Director for the GOM.
[67 FR 1878, Jan. 15, 2002]
§ 203.78
Do I keep relief if prices rise significantly?
If prices rise above a base price for light sweet crude oil or natural gas, set by statute for pre-Act leases, indicated in your original lease agreement or Notice of Sale for post-November 2000 deep water leases, you must pay full royalties as prescribed in this section. For post-November 2000 deepwater leases, price thresholds apply on a lease basis, so different leases on the same field, development project, or expansion project may have different price thresholds.
(a) Suppose the arithmetic average of the daily closing NYMEX light sweet crude oil prices for the previous calendar year exceeds $28.00 per barrel, as adjusted in paragraph (f) of this section. In this case, we retract the royalty relief authorized in this section 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 § 218.54 of this chapter) by March 31 of the current calendar year, and
(2) Pay royalties on all your oil production in the current year.
(b) Suppose the arithmetic average of the daily closing NYMEX natural gas prices for the previous calendar year exceeds $3.50 per million British thermal units (Btu), as adjusted in paragraph (f) of this section. In this case, we retract the royalty relief authorized in this section and you must:
(1) Pay royalties on all natural gas production for the previous year at the lease stipulated royalty rate plus interest (under 30 U.S.C. 1721 and § 218.54 of this chapter) by March 31 of the current calendar year, and
(2) Pay royalties on all your natural gas production in the current year.
(c) Production under both paragraphs (a) and (b) of this section counts as part of the royalty-suspension volume.
(d) 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 oil prices for the current calendar year is $28.00 per barrel or less, as adjusted in paragraph (f) 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 (f) of this section.
(e) You must follow our regulations in part 230 of this chapter for receiving refunds or credits.
(f) We change the prices referred to in paragraphs (a), (b), and (d) 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.
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1878, Jan. 15, 2002]
§ 203.79
How do I appeal MMS's decisions related to Deep Water Royalty Relief?
(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 MMS Director a letter within 15 days that also states your reasons. The MMS 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 MMS Director and stating your reasons. The MMS Director's response is the final agency action.
(d) We will notify you of all final agency actions by certified mail, return receipt requested. Final agency actions are not subject to appeal to the Interior Board of Land Appeals under 30 CFR part 290 and 43 CFR part 4. They are judicially reviewable under section 10(a) of the Administrative Procedure Act (5 U.S.C. 702) only if you file an action within 30 days of the date you receive our decision.
§ 203.80
When can I get royalty relief if I am not eligible for end-of-life or deep water royalty relief?
We may grant royalty relief when it serves the statutory purposes summarized in § 203.1, and our formal relief programs provide inadequate encouragement to increase production or development. Unless your lease lies wholly west of 87 degrees, 30 minutes West longitude in the Gulf of Mexico, your lease must be producing to qualify for relief. Before you may apply for royalty relief apart from our end-of-life or deepwater programs, 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 means 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.
[67 FR 1879, Jan. 15, 2002]

Required Reports
§ 203.81
What supplemental reports do royalty-relief applications require?
(a) You must send us the supplemental reports, indicated in the following table by an X, that apply to your field. Sections 203.83 through 203.91 describe these reports in detail.
Required reports | End-of-life lease | Deep water | Expansion project | Pre-act lease | Development project
(1) Administrative information Report | X | X | X | X
(2) Net revenue & relief justification report | X
(3) Economic viability & relief justification report (RSVP model imputs justified by other required reports). | | X | X | X
(4) G&G report. | | X | X | X
(5) Engineering report. | | X | X | X
(6) Production report. | | X | X | X
(7) Deep water cost report | | X | X | X
(8) Fabricator's confirmation report. | | X | X | X
(9) Post-production development report. | | X | X | X
(b) You must certify that all information in your application, fabricator's confirmation and post-production development reports is accurate, complete, and conforms to the most recent content and presentation guidelines available from the MMS GOM Regional Office.
(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.
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1879, Jan. 15, 2002]
§ 203.82
What is MMS'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(b) and part 250 of this chapter.
(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, Minerals Management Service, Mail Stop 4230, 1849 C Street, NW., Washington, DC 20240.
[63 FR 2618, Jan. 16, 1998, as amended at 65 FR 2875, Jan. 19, 2000]
§ 203.83
What is in an administrative information report?
This report identifies the field or lease for which royalty relief is requested and must contain the following items:
(a) The field or lease name;
(b) The serial number of leases we have assigned to the field, names of the lease title holders of record, the lease operators, and whether any lease is part of a unit;
(c) Well number, API number, location, and status of each well that has been drilled on the field or lease or project (not required for non-oil and gas leases);
(d) The location of any new wells proposed under the terms of the application (not required for non-oil and gas leases);
(e) A description of field or lease history;
(f) Full information as to whether you will pay royalties or a share of production to anyone other than the United States, the amount you will pay, and how much you will reduce this payment if we grant relief;
(g) The type of royalty relief you are requesting;
(h) Confirmation that we 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).
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1879, Jan. 15, 2002]
§ 203.84
What is in a net revenue and relief justification report?
This report presents cash flow data for 12 qualifying months, using the format specified in the “Guidelines for the Application, Review, Approval, and Administration of Royalty Relief for End-of-Life Leases”, U.S. Department of the Interior, MMS. 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 220.013 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;
(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.
[63 FR 2618, Jan. 16, 1998, as amended at 63 FR 57249, Oct. 27, 1998]
§ 203.85
What is in an economic viability and relief justification report?
This report should show that your project appears economic without royalties and sunk costs using the RSVP model we provide. The format of the report and the assumptions and parameters we specify are found in the “Guidelines for the Application, Review, Approval and Administration of the Deep Water Royalty Relief Program,” U.S. Department of the Interior, MMS. Clearly justify each parameter you set in every scenario you specify in the RSVP. You may provide supplemental information, including your own model and results. The economic viability and relief justification report must contain the following items for an oil and gas lease.
(a) Economic assumptions we provide which include:
(1) Starting oil and gas prices;
(2) Real price growth;
(3) Real cost growth or decline rate, if any;
(4) Base year;
(5) Range of discount rates; and
(6) Tax rate (for use in determining after-tax sunk costs).
(b) Analysis of projected cash flow (from the date of the application using annual totals and constant dollar values) which shows:
(1) Oil and gas production;
(2) Total revenues;
(3) Capital expenditures;
(4) Operating costs;
(5) Transportation costs; and
(6) Before-tax net cash flow without royalties, overrides, sunk costs, and ineligible costs.
(c) Discounted values which include:
(1) Discount rate used (selected from within the range we specify).
(2) Before-tax net present value without royalties, overrides, sunk costs, and ineligible costs.
(d) Demonstrations that:
(1) All costs, gross production, and scheduling are consistent with the data in the G&G, engineering, production, and cost reports (§§ 203.86 through 203.89) and
(2) The development and production scenarios provided in the various reports are consistent with each other and with the proposed development system. You can use up to three scenarios (conservative, most likely, and optimistic), but you must link each to a specific range on the distribution of resources from the RSVP Resource Module.
§ 203.86
What is in a G&G report?
This report supports the reserve and resource estimates used in the economic evaluation and must contain each of the following elements.
(a) Seismic data which includes:
(1) Non-interpreted 2D/3D survey lines reflecting any available state-of-the-art processing technique in a format readable by MMS 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 will be related to the most likely development and production scenario; and, the high end range will be consistent with the optimistic development and production scenario.
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1879, Jan. 15, 2002]
§ 203.87
What is in an engineering report?
This report defines the development plan and capital requirements for the economic evaluation and must contain the following elements.
(a) A description of the development concept (e.g., tension leg platform, fixed platform, floater type, subsea tieback, etc.) which includes:
(1) Its size along with basic design specifications and drawings; and
(2) The construction schedule.
(b) An identification of planned wells which includes:
(1) The number;
(2) The type (platform, subsea, vertical, deviated, horizontal);
(3) The well depth;
(4) The drilling schedule;
(5) The kind of completion (single, dual, horizontal, etc.); and
(6) The completion schedule.
(c) A description of the production system equipment which includes:
(1) The production capacity for oil and gas and a description of limiting component(s);
(2) Any unusual problems (low gravity, paraffin, etc.);
(3) All subsea structures;
(4) All flowlines; and
(5) Schedule for installing the production system.
(d) A discussion of any plans for multi-phase development which includes the conceptual basis for developing in phases and goals or milestones required for starting later phases.
(e) A set of development scenarios consisting of activity timing and scale associated with each of up to three production profiles (conservative, most likely, optimistic) provided in the production report for your field (§ 203.88). Each development scenario and production profile must denote the likely events should the field size turn out to be within a range represented by one of the three segments of the field size distribution. If you send in fewer than three scenarios, you must explain why fewer scenarios are more efficient across the whole field size distribution.
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1880, Jan. 15, 2002]
§ 203.88
What is in a production report?
This report supports your development and production timing and product quality expectations and must contain the following elements.
(a) Production profiles by well completion and field that specify the actual and projected production by year for each of the following products: oil, condensate, gas, and associated gas. The production from each profile must be consistent with a specific level of reserves and resources on the aggregated distribution of field size.
(b) Production drive mechanisms for each reservoir.
§ 203.89
What is in a deep water 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).
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1880, Jan. 15, 2002]
§ 203.90
What is in a fabricator's confirmation report?
This report shows you have committed in a timely way to the approved system for production. This report must include the following (or its equivalent for unconventionally acquired systems):
(a) A copy of the contract(s) under which the fabrication yard is building the approved system for you;
(b) A letter from the contractor building the system to the MMS's GOM Regional Supervisor—Production and Development, certifying when construction started on your system; and
(c) Evidence of an appropriate down payment or equal action that you've started acquiring the approved system.
§ 203.91
What is in a post-production development report?
For each cost category in the deep water cost report, you must compare actual costs up to the date when production starts to your planned 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).
[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1880, Jan. 15, 2002]
Subpart C—Federal and Indian Oil [Reserved]
Subpart D—Federal and Indian Gas [Reserved]
Subpart E—Solid Minerals, General [Reserved]

Subpart F—Coal
§ 203.250
Advance royalty.
Provisions for the payment of advance royalty in lieu of continued operation are contained at 43 CFR 3483.4.
[54 FR 1522, Jan. 13, 1989]
§ 203.251
Reduction in royalty rate or rental.
An application for reduction in coal royalty rate or rental shall be filed and processed in accordance with 43 CFR group 3400.
[54 FR 1522, Jan. 13, 1989]
Subpart G—Other Solid Minerals [Reserved]
Subpart H—Geothermal Resources [Reserved]
Subpart I—OCS Sulfur [Reserved]
Pt. 204

PART 204—ALTERNATIVES FOR MARGINAL PROPERTIES

Subpart A—General Provisions
Sec.
204.1
What is the purpose of this part?
204.2
What definitions apply to this part?
204.3
What alternatives are available for marginal properties?
204.4
What is a marginal property under this part?
204.5
What statutory requirements must I meet to obtain royalty prepayment or accounting and auditing relief?
204.6
May I appeal if MMS denies my request for prepayment or other relief?
Subpart B—Prepayment of Royalty [Reserved]

Subpart C—Accounting and Auditing Relief
204.200
What is the purpose of this subpart?
204.201
Who may obtain accounting and auditing relief?
204.202
What is the cumulative royalty reports and payments relief option?
204.203
What is the other relief option?
204.204
What accounting and auditing relief will MMS not allow?
204.205
How do I obtain accounting and auditing relief?
204.206
What will MMS do when it receives my request for other relief?
204.207
Who will approve, deny, or modify my request for accounting and auditing relief?
204.208
May a State decide that it will or will not allow one or both of the relief options under this subpart?
204.209
What if a property ceases to qualify for relief obtained under this subpart?
204.210
What if a property is approved as part of a nonqualifying agreement?
204.211
When may MMS rescind relief for a property?
204.212
What if I took relief for which I was ineligible?
204.213
May I obtain relief for a property that benefits from other Federal or State incentive programs?
204.214
Is minimum royalty due on a property for which I took relief?
204.215
Are the information collection requirements in this subpart approved by the Office of Management and Budget (OMB)?

Authority:
30 U.S.C. 1701 et seq.

Source:
69 FR 55088, Sept. 13, 2004, unless otherwise noted.

Subpart A—General Provisions
§ 204.1
What is the purpose of this part?
This part explains how you as a lessee or designee of a Federal onshore or Outer Continental Shelf (OCS) oil and gas lease may obtain prepayment or accounting and auditing relief for production from certain marginal properties. This part does not apply to production from Indian leases, even if the Indian lease is within an agreement that qualifies as a marginal property.
§ 204.2
What definitions apply to this part?
Agreement means a federally approved communitization agreement or unit participating area.
Barrels of oil equivalent (BOE) means the combined equivalent production of oil and gas stated in barrels of oil. Each barrel of oil production is equal to one BOE. Also, each 6,000 cubic feet of gas production is equal to one BOE.
Base period means the 12-month period from July 1 through June 30 immediately preceding the calendar year for which you take or request marginal property relief. For example, if you request relief for calendar year 2006, your base period is July 1, 2004, through June 30, 2005.
Combined equivalent production means the total of all oil and gas production for the marginal property, stated in BOE.
Designee means the person designated by a lessee under 30 CFR 218.52 to make all or part of the royalty or other payments due on a lease on the lessee's behalf.
Producing wells means only those producing oil or gas wells that contribute to the sum of BOE used in the calculation under § 204.4(c). Producing wells do not include injection or water wells. Wells with multiple zones commingled downhole are considered as a single well.
Property means a lease, a portion of a lease, or an agreement that may be a marginal property if it meets the qualification requirements of § 204.4.
State concerned (State) means the State that receives a statutorily prescribed portion of the royalties from a Federal onshore or OCS lease.
§ 204.3
What alternatives are available for marginal properties?
If you have production from a marginal property, MMS and the State may allow you the following options:
(a) Prepay royalty. MMS and the State may allow you to make a lump-sum advance payment of royalties instead of monthly royalty payments for the remainder of the lease term. See Subpart B for prepayment of royalty requirements.
(b) Take accounting and auditing relief. MMS and the State may allow various accounting and auditing relief options to encourage you to continue to produce and develop your marginal property. See Subpart C for accounting and auditing relief requirements.
§ 204.4
What is a marginal property under this part?
(a) To qualify as a marginal property eligible for royalty prepayment or accounting and auditing relief under this part, the property must meet the following requirements:
If your lease is . . . | Then . . . | And . . .
(1) Not in an agreement | The lease must qualify as a marginal property under paragraph (b) of this section |
(2) Entirely or partly committed to one agreement | The entire agreement must qualify as a marginal property under paragraph (b) of this section | Agreement production allocable to your lease may be eligible for relief under this part. Any production from your lease that is not committed to the agreement also may be eligible for separate relief under paragraph (a)(4) of this table.
(3) Entirely or partly committed to more than one agreement | Each agreement must qualify separately as a marginal property under paragraph (b) of this section | For any agreement that does qualify, that agreement's production allocable to your lease may be eligible for relief under this part. Any production from your lease that is not committed to an agreement also may be eligible for separate relief under paragraph (a)(4) of this table.
(4) Partly committed to an agreement and you have production from the part of the lease that is not committed to the agreement | The part of the lease that is not committed to the agreement must qualify separately as a marginal property under paragraph (b) of this section
(b) To qualify as a marginal property for a calendar year, the combined equivalent production of the property during the base period must equal an average daily well production of less than 15 barrels of oil equivalent (BOE) per well per day calculated under paragraph (c) of this section.
(c) To determine the average daily well production for a property, divide the sum of the BOE for all producing wells on the property during the base period by the sum of the number of days that each of those wells actually produced during the base period. If the property is an agreement, your calculation under this paragraph must include all wells included in the agreement, even if they are not on a Federal onshore or OCS lease.
§ 204.5
What statutory requirements must I meet to obtain royalty prepayment or accounting and auditing relief?
(a) MMS and the State may allow royalty prepayment or accounting and auditing relief for your marginal property production if MMS and the State jointly determine that the prepayment or accounting and auditing relief is in the best interests of the Federal Government and the State to:
(1) Promote production;
(2) Reduce the administrative costs of MMS and the State; and
(3) Increase net receipts to the Federal Government and the State.
(b) At any time, if MMS and the State determine that either prepayment or accounting and auditing relief no longer meets the criteria in paragraph (a) of this section, MMS, with the State's concurrence, may discontinue any prepayment or accounting and auditing relief options granted for production from any marginal property.
(1) MMS will provide you written notice of the decision to discontinue relief.
(i) If you took the cumulative reports and payments relief option under § 204.202, your relief will terminate at the end of the calendar year in which you received the notice.
(ii) If you were approved for prepayment relief under subpart B of this part or other relief under § 204.203, MMS's notice will tell you when your relief terminates.
(2) MMS's decision to discontinue relief is not subject to administrative appeal.
§ 204.6
May I appeal if MMS denies my request for prepayment or other relief?
If MMS denies your request for prepayment relief under Subpart B of this part or other relief under § 204.203, you may appeal under 30 CFR part 290.
Subpart B—Prepayment of Royalty [Reserved]

Subpart C—Accounting and Auditing Relief
§ 204.200
What is the purpose of this subpart?
This subpart explains how you as a lessee or designee may obtain accounting and auditing relief for your Federal onshore or OCS lease production from a marginal property. The two types of accounting and auditing relief that you can receive under this subpart are cumulative reports and payment relief (explained in § 204.202) and other accounting and auditing relief appropriate for your property (explained in § 204.203).
§ 204.201
Who may obtain accounting and auditing relief?
(a) You may obtain accounting and auditing relief under this subpart:
(1) If you are a lessee or a designee for a Federal lease with production from a property that qualifies as a marginal property under § 204.4;
(2) If you meet any additional requirements for specific types of relief under this subpart; and
(3) Only for the fractional interest in production from the marginal property for which you report and pay royalty. You may obtain relief even if the other lessees or designees for your lease or agreement do not request relief.
(b) You may not obtain one or both of the relief options specified in this subpart on any portion of production from a marginal property if:
(1) The marginal property covers multiple States; and
(2) One of the States determines under § 204.208 that it will not allow the relief option you seek.
§ 204.202
What is the cumulative royalty reports and payments relief option?
(a) The cumulative royalty reports and payments relief option allows you to submit one royalty report and payment annually for production during a calendar year. You are eligible for this option only if the total volume produced from the marginal property (not just your share of the production) is 1,000 BOE or less during the base period.
(b) To use the cumulative royalty reports and payments relief option, you must do all of the following:
(1) Notify MMS in writing by January 31 of the calendar year for which you begin taking your relief. See § 204.205(a) for what your notification must contain;
(2) Submit your royalty report and payment in accordance with 30 CFR 218.51(g) by the end of February of the year following the calendar year for which you reported annually, unless you have an estimated payment on file. If you have an estimated payment on file, you must submit your royalty report and payment by the end of March of the year following the calendar year for which you reported annually;
(3) Use the sales month prior to the month that you submit your annual report and payment under paragraph (b)(2) of this section on your Report of Sales and Royalty Remittance, Form MMS-2014, for the entire previous calendar year's production for which you are paying annually. (For example, for a report in February use January as your sales month, and for a report in March use February as your sales month, to report production for the entire previous calendar year for which you are paying annually);
(4) Report one line of cumulative royalty information on Form MMS-2014 for the calendar year, the same as if it were a monthly report; and
(5) Report allowances on Form MMS-2014 on the same annual basis as the royalties for your marginal property production.
(c) If you do not pay your royalty by the date due in paragraph (b) of this section, you will owe late payment interest determined under 30 CFR 218.54 from the date your payment was due under this section until the date MMS receives it.
(d) If you take relief you are not qualified for, you may be liable for civil penalties. Also you must:
(1) Pay MMS late payment interest determined under 30 CFR 218.54 from the date your payment was due until the date MMS receives it; and
(2) Amend your Form MMS-2014 to reflect the required monthly reporting.
(e) If you dispose of your ownership interest in a marginal property for which you have taken relief under this section (or if you are a designee who reports and pays royalty for a lessee who has disposed of its ownership interest), you must:
(1) Report and pay royalties for the portion of the calendar year for which you had an ownership interest; and
(2) Make the report and payment by the end of the month after you dispose of the ownership interest in the marginal property. If you do not report and pay timely, you will owe interest determined under 30 CFR 218.54 from the date the payment was due under this section.
§ 204.203
What is the other relief option?
(a) Under this relief option, you may request any type of accounting and auditing relief that is appropriate for production from your marginal property, provided it is not prohibited under § 204.204 and meets the statutory requirements of § 204.5. Examples of relief options you could request are:
(1) To report and pay royalties using a valuation method other than that required under 30 CFR part 206 that approximates royalties payable under that part 206; and
(2) To reduce your royalty audit burden. However, MMS will not consider any request that eliminates MMS's or the States' right to audit.
(b) You must request approval from MMS under § 204.205(b), and receive approval under § 204.206 before taking relief under this option.
§ 204.204
What accounting and auditing relief will MMS not allow?
MMS will not approve your request for accounting and auditing relief under this subpart if your request:
(a) Prohibits MMS or the State from conducting any form of audit;
(b) Permanently relieves you from making future royalty reports or payments;
(c) Provides for less frequent royalty reports and payments than annually;
(d) Provides for you to submit royalty reports and payments at separate times;
(e) Impairs MMS's ability to properly or efficiently account for or distribute royalties;
(f) Requests relief for a lease under which the Federal Government takes its royalties in kind;
(g) Alters production reporting requirements;
(h) Alters lease operation or safety requirements;
(i) Conflicts with rent, minimum royalty, or lease requirements; or
(j) Requests relief for production from a marginal property located in whole or in part in a State that has determined that it will not allow such relief under § 204.208.
§ 204.205
How do I obtain accounting and auditing relief?
(a) To take cumulative reports and payments relief under § 204.202, you must notify MMS in writing by January 31 of the calendar year for which you begin taking your relief.
(1) Your notification must contain:
(i) Your company name, MMS-assigned payor code, address, phone number, and contact name; and
(ii) The specific MMS lease number and agreement number, if applicable.
(2) You may file a single notification for multiple marginal properties.
(b) To obtain other relief under § 204.203, you must file a written request for relief with MMS.
(1) Your request must contain:
(i) Your company name, MMS-assigned payor code, address, phone number, and contact name;
(ii) The MMS lease number and agreement number, if applicable; and
(iii) A complete and detailed description of the specific accounting or auditing relief you seek.
(2) You may file a single request for multiple marginal properties if you are requesting the same relief for all properties.
§ 204.206
What will MMS do when it receives my request for other relief?
When MMS receives your request for other relief under § 204.205(b), it will notify you in writing as follows:
(a) If your request for relief is complete, MMS may either approve, deny, or modify your request in writing after consultation with any State required under § 204.207(b).
(1) If MMS approves your request for relief, MMS will notify you of the effective date of your accounting or auditing relief and other specifics of the relief approved.
(2) If MMS denies your relief request, MMS will notify you of the reasons for denial and your appeal rights under § 204.6.
(3) If MMS modifies your relief request, MMS will notify you of the modifications.
(i) You have 60 days from your receipt of MMS's notice to either accept or reject any modification(s) in writing.
(ii) If you reject the modification(s) or fail to respond to MMS's notice, MMS will deny your relief request. MMS will notify you in writing of the reasons for denial and your appeal rights under § 204.6.
(b) If your request for relief is not complete, MMS will notify you in writing that your request is incomplete and identify any missing information.
(1) You must submit the missing information within 60 days of your receipt of MMS's notice that your request is incomplete.
(2) After you submit all required information, MMS may approve, deny, or modify your request for relief under paragraph (a) of this section.
(3) If you do not submit all required information within 60 days of your receipt of MMS's notice that your request is incomplete, MMS will deny your relief request. MMS will notify you in writing of the reasons for denial and your appeal rights under § 204.6.
(4) You may submit a new request for relief under this subpart at any time after MMS returns your incomplete request.
§ 204.207
Who will approve, deny, or modify my request for accounting and auditing relief?
(a) If there is not a State concerned for your marginal property, only MMS will decide whether to approve, deny, or modify your relief request.
(b) If there is a State concerned for your marginal property that has determined in advance under § 204.208 that it will allow either or both of the relief options under this subpart, MMS will decide whether to approve, deny, or modify your relief request after consulting with the State concerned.
§ 204.208
May a State decide that it will or will not allow one or both of the relief options under this subpart?
(a) A State may decide in advance that it will or will not allow one or both of the relief options specified in this subpart for a particular calendar year. If a State decides that it will not consent to one or both of the relief options, MMS will not grant that type of marginal property relief.
(b) To help States decide whether to allow one or both of the relief options specified in this subpart, for each calendar year MMS will send States a Report of Marginal Properties by October 1 preceding the calendar year.
(c) If a State decides under paragraph (a) of this section that it will or will not allow one or both of the relief options in this subpart during the next calendar year, within 30 days of the State's receipt of the Report of Marginal Properties under paragraph (b) of this section, the State must:
(1) Notify the Associate Director for Minerals Revenue Management, MMS, in writing, of its intent to allow or not allow one or both of the relief options under this subpart; and
(2) Specify in its notice of intent to MMS which relief option(s) it will allow or not allow.
(d) If a State decides in advance under paragraph (a) of this section that it will not allow one or both of the relief options specified in this subpart, it may decide for subsequent calendar years that it will allow one or both of the relief options in this subpart. If it so decides, within 30 days of the State's receipt of the Report of Marginal Properties under paragraph (b) of this section, the State must:
(1) Notify the Associate Director for Minerals Revenue Management, MMS, in writing, of its intent to allow one or both of the relief options allowed under this subpart during the next calendar year; and
(2) Specify in its notice of intent to MMS which relief option(s) it will allow.
(e) If a State does not notify MMS under paragraph (c) or (d) of this section, the State will be deemed to have decided not to allow either of the relief options under this subpart for the next calendar year.
(f) MMS will publish a notice of the State s intent to allow or not allow certain relief options under this section in the Federal Register no later than 30 days before the beginning of the applicable calendar year.
§ 204.209
What if a property ceases to qualify for relief obtained under this subpart?
(a) A marginal property must qualify for relief under this subpart for each calendar year based on production during the base period for that calendar year. The notice or request you provided to MMS under § 204.205 for the first calendar year that the property qualified for relief remains effective for successive calendar years if the property continues to qualify.
(b) If a property is no longer eligible for relief for any reason during a calendar year other than the reason under § 204.210 or paragraph (c) of this section, the relief for the property terminates as of December 31 of that calendar year. You must notify MMS in writing by December 31 that the relief for the property has terminated.
(c) If you dispose of your interest in a marginal property during the calendar year, your relief terminates as of the end of the sales month in which you disposed of the property. Report and pay royalties for your production using the procedures in § 204.202(e).
§ 204.210
What if a property is approved as part of a nonqualifying agreement?
If the Bureau of Land Management (BLM) or MMS's Offshore Minerals Management (OMM) retroactively approves a marginal property that qualified for relief for inclusion as part of an agreement that does not qualify for relief under this subpart, the property no longer qualifies for relief under this subpart then:
(a) MMS will not retroactively rescind the marginal property relief for production from your property under § 204.211;
(b) Your marginal property relief terminates as of December 31 of the calendar year that you receive the BLM or OMM approval of your marginal property as part of a nonqualifying agreement; and
(c) For the calendar year in which you receive the BLM or OMM approval, and for any previous period affected by the approval, the volumes on which you report and pay royalty for your lease must be amended to reflect all volumes produced on or allocated to your lease under the nonqualifying agreement as modified by BLM or OMM. Report and pay royalties for your production using the procedures in § 204.202(b).
(d) If you owe additional royalties based on the retroactive agreement approval and do not pay your royalty by the date due in § 204.202(b), you will owe late payment interest determined under 30 CFR 218.54 from the date your payment was due under § 204.202 (b)(2) until the date MMS receives it.
§ 204.211
When may MMS rescind relief for a property?
(a) MMS may retroactively rescind the relief for your property if MMS determines that your property was not eligible for the relief obtained under this subpart because:
(1) You did not submit a notice or request for relief under § 204.205;
(2) You submitted erroneous information in the notice or request for relief you provided to MMS under § 204.205 or in your royalty or production reports; or
(3) Your property is no longer eligible for relief because production increased, but you failed to provide the notice required under § 204.209(b).
(b) MMS may rescind relief for your property if MMS decides to take royalty in kind.
§ 204.212
What if I took relief for which I was ineligible?
If you took relief under this subpart for a period for which you were not eligible, you:
(a) May owe additional royalties and late payment interest determined under 30 CFR 218.54 from the date your additional payments were due until the date MMS receives them; and
(b) May be subject to civil penalties.
§ 204.213
May I obtain relief for a property that benefits from other Federal or State incentive programs?
You may obtain accounting and auditing relief for production from a marginal property under this subpart even if the property benefits from other Federal or State production incentive programs.
§ 204.214
Is minimum royalty due on a property for which I took relief?
(a) If you took cumulative royalty reports and payment relief on a property under this subpart, minimum royalty is still due for that property by the date prescribed in your lease and in the amount prescribed therein.
(b) If you pay minimum royalty on production from a marginal property during a calendar year for which you are taking cumulative royalty reports and payment relief, and:
(1) The annual payment you owe under this subpart is greater than the minimum royalty you paid, you must pay the difference between the minimum royalty you paid and your annual payment due under this subpart; or
(2) The annual payment you owe under this subpart is less than the minimum royalty you paid, you are not entitled to a credit because you must pay at least the minimum royalty amount on your lease each year.
§ 204.215
Are the information collection requirements in this subpart approved by the Office of Management and Budget (OMB)?
OMB has approved the information collection requirements contained in this subpart under 44 U.S.C. 3501 et seq., and assigned OMB control number 1010-0155. See 30 CFR part 210 for details concerning your estimated reporting burden and how you may comment on the accuracy of the burden estimate.
Pt. 206

PART 206—PRODUCT VALUATION

Subpart A—General Provisions
Sec.
206.10
Information collection.

Subpart B—Indian Oil
206.50
What is the purpose of this subpart?
206.51
What definitions apply to this subpart?
206.52
How do I calculate royalty value for oil that I or my affiliate sell(s) or exchange(s) under an arm's-length contract?
206.53
How do I determine value for oil that I or my affiliate do(es) not sell under an arm's-length contract?
206.54
How do I fulfill the lease provision regarding valuing production on the basis of the major portion of like-quality oil?
206.55
What are my responsibilities to place production into marketable condition and to market the production?
206.56
Transportation allowances—general.
206.57
Determination of transportation allowances.
206.58
What must I do if MMS finds that I have not properly determined value?
206.59
May I ask MMS for valuation guidance?
206.60
What are the quantity and quality bases for royalty settlement?
206.61
What records must I keep and produce?
206.62
Does MMS protect information I provide?

Subpart C—Federal Oil
206.100
What is the purpose of this subpart?
206.101
What definitions apply to this subpart?
206.102
How do I calculate royalty value for oil that I or my affiliate sell(s) under an arm's-length contract?
206.103
How do I value oil that is not sold under an arm's-length contract?
206.104
What publications are acceptable to MMS?
206.105
What records must I keep to support my calculations of value under this subpart?
206.106
What are my responsibilities to place production into marketable condition and to market production?
206.107
How do I request a value determination?
206.108
Does MMS protect information I provide?
206.109
When may I take a transportation allowance in determining value?
206.110
How do I determine a transportation allowance under an arm's-length transportation contract?
206.111
How do I determine a transportation allowance if I do not have an arm's-length transportation contract or arm's-length tariff?
206.112
What adjustments and transportation allowances apply when I value oil production from my lease using NYMEX prices or ANS spot prices?
206.113
How will MMS identify market centers?
206.114
What are my reporting requirements under an arm's-length transportation contract?
206.115
What are my reporting requirements under a non-arm's-length transportation arrangement?
206.116
What interest applies if I improperly report a transportation allowance?
206.117
What reporting adjustments must I make for transportation allowances?
206.119
How are the royalty quantity and quality determined?
206.120
How are operating allowances determined?

Subpart D—Federal Gas
206.150
Purpose and scope.
206.151
Definitions.
206.152
Valuation standards—unprocessed gas.
206.153
Valuation standards—processed gas.
206.154
Determination of quantities and qualities for computing royalties.
206.155
Accounting for comparison.
206.156
Transportation allowances—general.
206.157
Determination of transportation allowances.
206.158
Processing allowances—general.
206.159
Determination of processing allowances.
206.160
Operating allowances.

Subpart E—Indian Gas
206.170
What does this subpart contain?
206.171
What definitions apply to this subpart?
206.172
How do I value gas produced from leases in an index zone?
206.173
How do I calculate the alternative methodology for dual accounting?
206.174
How do I value gas production when an index-based method cannot be used?
206.175
How do I determine quantities and qualities of production for computing royalties?
206.176
How do I perform accounting for comparison?

Transportation Allowances
206.177
What general requirements regarding transportation allowances apply to me?
206.178
How do I determine a transportation allowance?

Processing Allowances
206.179
What general requirements regarding processing allowances apply to me?
206.180
How do I determine an actual processing allowance?
206.181
How do I establish processing costs for dual accounting purposes when I do not process the gas?

Subpart F—Federal Coal
206.250
Purpose and scope.
206.251
Definitions.
206.252
Information collection.
206.253
Coal subject to royalties—general provisions.
206.254
Quality and quantity measurement standards for reporting and paying royalties.
206.255
Point of royalty determination.
206.256
Valuation standards for cents-per-ton leases.
206.257
Valuation standards for ad valorem leases.
206.258
Washing allowances—general.
206.259
Determination of washing allowances.
206.260
Allocation of washed coal.
206.261
Transportation allowances—general.
206.262
Determination of transportation allowances.
206.263
[Reserved]
206.264
In-situ and surface gasification and liquefaction operations.
206.265
Value enhancement of marketable coal.

Subpart G—Other Solid Minerals
206.301
Value basis for royalty computation.

Subpart H—Geothermal Resources
206.350
What is the purpose of this subpart?
206.351
What definitions apply to this subpart?
206.352
How do I calculate the royalty due on geothermal resources used for commercial production or generation of electricity?
206.353
How do I determine transmission deductions?
206.354
How do I determine generating deductions?
206.355
How do I calculate royalty due on geothermal resources I sell at arm's length to a purchaser for direct use?
206.356
How do I calculate royalty due on geothermal resources I use for direct use purposes?
206.357
How do I calculate royalty due on byproducts?
206.358
What are byproduct transportation allowances?
206.359
How do I determine byproduct transportation allowances?
206.360
What records must I keep to support my calculations of royalty or fees under this subpart?
206.361
How will MMS determine whether my royalty or direct use fee payments are correct?
206.362
What are my responsibilities to place production into marketable condition and to market production?
206.363
When is an MMS audit, review, reconciliation, monitoring, or other like process considered final?
206.364
How do I request a value or gross proceeds determination?
206.365
Does MMS protect information I provide?
206.366
What is the nominal fee that a State, tribal, or local government lessee must pay for the use of geothermal resources?
Subpart I—OCS Sulfur [Reserved]

Subpart J—Indian Coal
206.450
Purpose and scope.
206.451
Definitions.
206.452
Coal subject to royalties—general provisions.
206.453
Quality and quantity measurement standards for reporting and paying royalties.
206.454
Point of royalty determination.
206.455
Valuation standards for cents-per-ton leases.
206.456
Valuation standards for ad valorem leases.
206.457
Washing allowances—general.
206.458
Determination of washing allowances.
206.459
Allocation of washed coal.
206.460
Transportation allowances—general.
206.461
Determination of transportation allowances.
206.462
[Reserved]
206.463
In-situ and surface gasification and liquefaction operations.
206.464
Value enhancement of marketable coal.

Authority:
5 U.S.C. 301 et seq.; 25 U.S.C. 396 et seq., 396a et seq., 2101 et seq.; 30 U.S.C. 181 et seq., 351 et seq., 1001 et seq., 1701 et seq.; 31 U.S.C. 9701.; 43 U.S.C. 1301 et seq., 1331 et seq., and 1801 et seq.

Editorial Note:
Nomenclature changes to part 206 appear at 67 FR 19111, Apr. 18, 2002.

Subpart A—General Provisions
§ 206.10
Information collection.
The information collection requirements contained in this part have been approved by the Office of Management and Budget (OMB) under 44 U.S.C. 3501 et seq. The forms, filing date, and approved OMB clearance numbers are identified in 30 CFR 210.10.
[57 FR 41863, Sept. 14, 1992]

Subpart B—Indian Oil

Source:
61 FR 5455, Feb. 12, 1996, unless otherwise noted.
§ 206.50
What is the purpose of this subpart?
(a) This subpart applies to all oil produced from Indian (tribal and allotted) oil and gas leases (except leases on the Osage Indian Reservation, Osage County, Oklahoma). This subpart does not apply to Federal leases, including Federal leases for which revenues are shared with Alaska Native Corporations. This subpart:
(1) Establishes the value of production for royalty purposes consistent with the Indian mineral leasing laws, other applicable laws, and lease terms;
(2) Explains how you as a lessee must calculate the value of production for royalty purposes consistent with applicable statutes and lease terms; and
(3) Is intended to ensure that the United States discharges its trust responsibilities for administering Indian oil and gas leases under the governing Indian mineral leasing laws, treaties, and lease terms.
(b) If the regulations in this subpart are inconsistent with a Federal statute, a settlement agreement or written agreement as these terms are defined in this paragraph, or an express provision of an oil and gas lease subject to this subpart, then the statute, settlement agreement, written agreement, or lease provision will govern to the extent of the inconsistency. For purposes of this paragraph:
(1) Settlement agreement means a settlement agreement that is between the United States and a lessee, or between an individual Indian mineral owner and a lessee and is approved by the United States, resulting from administrative or judicial litigation; and
(2) Written agreement means a written agreement between the lessee and the MMS Director (and approved by the tribal lessor for tribal leases) establishing a method to determine the value of production from any lease that MMS expects at least would approximate the value established under this subpart.
(c) The MMS or Indian tribes may audit, or perform other compliance reviews, and require a lessee to adjust royalty payments and reports.
[72 FR 71241, Dec. 17, 2007]
§ 206.51
What definitions apply to this subpart?
For purposes of this subpart:
Affiliate means a person who controls, is controlled by, or is under common control with another person.
(1) Ownership or common ownership of more than 50 percent of the voting securities, or instruments of ownership, or other forms of ownership, of another person constitutes control. Ownership of less than 10 percent constitutes a presumption of noncontrol that MMS may rebut.
(2) If there is ownership or common ownership of 10 through 50 percent of the voting securities or instruments of ownership, or other forms of ownership, of another person, MMS will consider the following factors in determining whether there is control in a particular case:
(i) The extent to which there are common officers or directors;
(ii) With respect to the voting securities, or instruments of ownership, or other forms of ownership:
(A) The percentage of ownership or common ownership;
(B) The relative percentage of ownership or common ownership compared to the percentage(s) of ownership by other persons;
(C) Whether a person is the greatest single owner; and
(D) Whether there is an opposing voting bloc of greater ownership;
(iii) Operation of a lease, plant, or other facility;
(iv) The extent of participation by other owners in operations and day-to-day management of a lease, plant, or other facility; and
(v) Other evidence of power to exercise control over or common control with another person.
(3) Regardless of any percentage of ownership or common ownership, relatives, either by blood or marriage, are affiliates.
Area means a geographic region at least as large as the defined limits of an oil and/or gas field in which oil and/or gas lease products have similar quality, economic, and legal characteristics.
Arm's-length contract means a contract or agreement between independent persons who are not affiliates and who have opposing economic interests regarding that contract. To be considered arm's length for any production month, a contract must satisfy this definition for that month, as well as when the contract was executed.
Audit means a review, conducted in accordance with generally accepted accounting and auditing standards, of royalty payment compliance activities of lessees or other interest holders who pay royalties, rents, or bonuses on Indian leases.
BLM means the Bureau of Land Management of the Department of the Interior.
Condensate means liquid hydrocarbons (generally exceeding 40 degrees of API gravity) recovered at the surface without resorting to processing. Condensate is the mixture of liquid hydrocarbons that results from condensation of petroleum hydrocarbons existing initially in a gaseous phase in an underground reservoir.
Contract means any oral or written agreement, including amendments or revisions thereto, between two or more persons and enforceable by law that with due consideration creates an obligation.
Exchange agreement means an agreement where one person agrees to deliver oil to another person at a specified location in exchange for oil deliveries at another location, and other consideration. Exchange agreements:
(1) May or may not specify prices for the oil involved;
(2) Frequently specify dollar amounts reflecting location, quality, or other differentials;
(3) Include buy/sell agreements, which specify prices to be paid at each exchange point and may appear to be two separate sales within the same agreement, or in separate agreements; and
(4) May include, but are not limited to, exchanges of produced oil for specific types of oil (e.g., WTI); exchanges of produced oil for other oil at other locations (location trades); exchanges of produced oil for other grades of oil (grade trades); and multi-party exchanges.
Field means a geographic region situated over one or more subsurface oil and gas reservoirs encompassing at least the outermost boundaries of all oil and gas accumulations known to be within those reservoirs vertically projected to the land surface. Onshore fields usually are given names, and their official boundaries are often designated by oil and gas regulatory agencies in the respective states in which the fields are located.
Gathering means the movement of lease production to a central accumulation or treatment point on the lease, unit, or communitized area, or to a central accumulation or treatment point off the lease, unit, or communitized area as approved by BLM operations personnel.
Gross proceeds means the total monies and other consideration accruing for the disposition of oil produced. Gross proceeds also include, but are not limited to, the following examples:
(1) Payments for services, such as dehydration, marketing, measurement, or gathering that the lessee must perform at no cost to the lessor in order to put the production into marketable condition;
(2) The value of services to put the production into marketable condition, such as salt water disposal, that the lessee normally performs but that the buyer performs on the lessee's behalf;
(3) Reimbursements for harboring or terminaling fees;
(4) Tax reimbursements, even though the Indian royalty interest may be exempt from taxation;
(5) Payments made to reduce or buy down the purchase price of oil to be produced in later periods, by allocating those payments over the production whose price the payment reduces and including the allocated amounts as proceeds for the production as it occurs; and
(6) Monies and all other consideration to which a seller is contractually or legally entitled, but does not seek to collect through reasonable efforts.
Indian tribe means any Indian tribe, band, nation, pueblo, community, rancheria, colony, or other group of Indians for which any minerals or interest in minerals is held in trust by the United States or that is subject to Federal restriction against alienation.
Individual Indian mineral owner means any Indian for whom minerals or an interest in minerals is held in trust by the United States or who holds title subject to Federal restriction against alienation.
Lease means any contract, profit-share arrangement, joint venture, or other agreement issued or approved by the United States under an Indian mineral leasing law that authorizes exploration for, development or extraction of, or removal of lease products. Depending on the context, lease may also refer to the land area covered by that authorization.
Lease products means any leased minerals attributable to, originating from, or allocated to Indian leases.
Lessee means any person to whom the United States, a tribe, or individual Indian mineral owner issues a lease, and any person who has been assigned an obligation to make royalty or other payments required by the lease. Lessee includes:
(1) Any person who has an interest in a lease (including operating rights owners); and
(2) An operator, purchaser, or other person with no lease interest who makes royalty payments to MMS or the lessor on the lessee's behalf
Lessor means an Indian tribe or individual Indian mineral owner who has entered into a lease.
Like-quality oil means oil that has similar chemical and physical characteristics.
Location differential means an amount paid or received (whether in money or in barrels of oil) under an exchange agreement that results from differences in location between oil delivered in exchange and oil received in the exchange. A location differential may represent all or part of the difference between the price received for oil delivered and the price paid for oil received under a buy/sell exchange agreement.
Marketable condition means lease products that are sufficiently free from impurities and otherwise in a condition that they will be accepted by a purchaser under a sales contract typical for the field or area.
MMS means the Minerals Management Service of the Department of the Interior.
Net means to reduce the reported sales value to account for transportation instead of reporting a transportation allowance as a separate entry on Form MMS-2014.
NYMEX price means the average of the New York Mercantile Exchange (NYMEX) settlement prices for light sweet oil delivered at Cushing, Oklahoma, calculated as follows:
(1) Sum the prices published for each day during the calendar month of production (excluding weekends and holidays) for oil to be delivered in the nearest month of delivery for which NYMEX futures prices are published corresponding to each such day; and
(2) Divide the sum by the number of days on which those prices are published (excluding weekends and holidays).
Oil means a mixture of hydrocarbons that existed in the liquid phase in natural underground reservoirs and remains liquid at atmospheric pressure after passing through surface separating facilities and is marketed or used as such. Condensate recovered in lease separators or field facilities is considered to be oil.
Operating rights owner, also known as a working interest owner, means any person who owns operating rights in a lease subject to this subpart. A record title owner is the owner of operating rights under a lease until the operating rights have been transferred from record title (see Bureau of Land Management regulations at 43 CFR 3100.0-5(d)).
Person means any individual, firm, corporation, association, partnership, consortium, or joint venture (when established as a separate entity).
Processing means any process designed to remove elements or compounds (hydrocarbon and nonhydrocarbon) from gas, including absorption, adsorption, or refrigeration. Field processes that normally take place on or near the lease, such as natural pressure reduction, mechanical separation, heating, cooling, dehydration, and compression, are not considered processing. The changing of pressures and/or temperatures in a reservoir is not considered processing.
Quality differential means an amount paid or received under an exchange agreement (whether in money or in barrels of oil) that results from differences in API gravity, sulfur content, viscosity, metals content, and other quality factors between oil delivered and oil received in the exchange. A quality differential may represent all or part of the difference between the price received for oil delivered and the price paid for oil received under a buy/sell agreement.
Sale means a contract between two persons where:
(1) The seller unconditionally transfers title to the oil to the buyer and does not retain any related rights such as the right to buy back similar quantities of oil from the buyer elsewhere;
(2) The buyer pays money or other consideration for the oil; and
(3) The parties' intent is for a sale of the oil to occur.
Sales type code means the contract type or general disposition (e.g., arm's-length or non-arm's-length) of production from the lease. The sales type code applies to the sales contract, or other disposition, and not to the arm's-length or non-arm's-length nature of a transportation allowance.
Transportation allowance means a deduction in determining royalty value for the reasonable, actual costs of moving oil to a point of sale or delivery off the lease, unit area, or communitized area. The transportation allowance does not include gathering costs.
WTI means West Texas Intermediate.
You means a lessee, operator, or other person who pays royalties under this subpart.
[72 FR 71241, Dec. 17, 2007, as amended at 73 FR 15890, Mar. 26, 2008]
§ 206.52
How do I calculate royalty value for oil that I or my affiliate sell(s) or exchange(s) under an arm's-length contract?
(a) The value of oil under this section is the gross proceeds accruing to the seller under the arm's-length contract, less applicable allowances determined under §§ 206.56 and 206.57. If the arm's-length sales contract does not reflect the total consideration actually transferred either directly or indirectly from the buyer to the seller, you must value the oil sold as the total consideration accruing to the seller. Use this section to value oil that:
(1) You sell under an arm's-length sales contract; or
(2) You sell or transfer to your affiliate or another person under a non-arm's-length contract and that affiliate or person, or another affiliate of either of them, then sells the oil under an arm's-length contract.
(b) If you have multiple arm's-length contracts to sell oil produced from a lease that is valued under paragraph (a) of this section, the value of the oil is the volume-weighted average of the total consideration established under this section for all contracts for the sale of oil produced from that lease.
(c) If MMS determines that the value under paragraph (a) of this section does not reflect the reasonable value of the production due to either:
(1) Misconduct by or between the parties to the arm's-length contract; or
(2) Breach of your duty to market the oil for the mutual benefit of yourself and the lessor, MMS will establish a value based on other relevant matters.
(i) The MMS will not use this provision to simply substitute its judgment of the market value of the oil for the proceeds received by the seller under an arm's-length sales contract.
(ii) The fact that the price received by the seller under an arm's-length contract is less than other measures of market price is insufficient to establish breach of the duty to market unless MMS finds additional evidence that the seller acted unreasonably or in bad faith in the sale of oil produced from the lease.
(d) You must base value on the highest price that the seller can receive through legally enforceable claims under the oil sales contract. If the seller fails to take proper or timely action to receive prices or benefits to which it is entitled, you must base value on that obtainable price or benefit.
(1) In some cases the seller may apply timely for a price increase or benefit allowed under the oil sales contract, but the purchaser refuses the seller's request. If this occurs, and the seller takes reasonable documented measures to force purchaser compliance, you will owe no additional royalties unless or until the seller receives monies or consideration resulting from the price increase or additional benefits. This paragraph (d)(1) does not permit you to avoid your royalty payment obligation if a purchaser fails to pay, pays only in part, or pays late.
(2) Any contract revisions or amendments that reduce prices or benefits to which the seller is entitled must be in writing and signed by all parties to the arm's-length contract.
(e) If you or your affiliate enter(s) into an arm's-length exchange agreement, or multiple sequential arm's-length exchange agreements, then you must value your oil under this paragraph.
(1) If you or your affiliate exchange(s) oil at arm's length for WTI or equivalent oil at Cushing, Oklahoma, you must value the oil using the NYMEX price, adjusted for applicable location and quality differentials under paragraph (e)(3) of this section and any transportation costs under paragraph (e)(4) of this section and §§ 206.56 and 206.57.
(2) If you do not exchange oil for WTI or equivalent oil at Cushing, but exchange it at arm's length for oil at another location and following the arm's-length exchange(s) you or your affiliate sell(s) the oil received in the exchange(s) under an arm's-length contract, then you must use the gross proceeds under your or your affiliate's arm's-length sales contract after the exchange(s) occur(s), adjusted for applicable location and quality differentials under paragraph (e)(3) of this section and any transportation costs under paragraph (e)(4) of this section and §§ 206.56 and 206.57.
(3) You must adjust your gross proceeds for any location or quality differential, or other adjustments, you received or paid under the arm's-length exchange agreement(s). If MMS determines that any exchange agreement does not reflect reasonable location or quality differentials, MMS may adjust the differentials you used based on relevant information. You may not otherwise use the price or differential specified in an arm's-length exchange agreement to value your production.
(4) If you value oil under this paragraph, MMS will allow a deduction, under §§ 206.56 and 206.57, for the reasonable, actual costs to transport the oil:
(i) From the lease to a point where oil is given in exchange; and
(ii) If oil is not exchanged to Cushing, Oklahoma, from the point where oil is received in exchange to the point where the oil received in exchange is sold.
(5) If you or your affiliate exchange(s) your oil at arm's length, and neither paragraph (e)(1) nor (e)(2) of this section applies, MMS will establish a value for the oil based on relevant matters. After MMS establishes the value, you must report and pay royalties and any late payment interest owed based on that value.
(f) You may not deduct any costs of gathering as part of a transportation deduction or allowance.
(g) You must also comply with § 206.54.
[72 FR 71241, Dec. 17, 2007]
§ 206.53
How do I determine value for oil that I or my affiliate do(es) not sell under an arm's-length contract?
(a) The unit value of your oil not sold under an arm's-length contract is the volume-weighted average of the gross proceeds paid or received by you or your affiliate, including your refining affiliate, for purchases or sales under arm's-length contracts.
(1) When calculating that unit value, use only purchases or sales of other like-quality oil produced from the field (or the same area if you do not have sufficient arm's-length purchases or sales of oil produced from the field) during the production month.
(2) You may adjust the gross proceeds determined under paragraph (a) of this section for transportation costs under paragraph (c) of this section and §§ 206.56 and 206.57 before including those proceeds in the volume-weighted average calculation.
(3) If you have purchases away from the field(s) and cannot calculate a price in the field because you cannot determine the seller's cost of transportation that would be allowed under paragraph (c) of this section and §§ 206.56 and 206.57, you must not include those purchases in your weighted-average calculation.
(b) Before calculating the volume-weighted average, you must normalize the quality of the oil in your or your affiliate's arm's-length purchases or sales to the same gravity as that of the oil produced from the lease. Use applicable gravity adjustment tables for the field (or the same general area for like-quality oil if you do not have gravity adjustment tables for the specific field) to normalize for gravity.

Example to paragraph (b):
1. Assume that a lessee, who owns a refinery and refines the oil produced from the lease at that refinery, purchases like-quality oil from other producers in the same field at arm's length for use as feedstock in its refinery. Further assume that the oil produced from the lease that is being valued under this section is Wyoming general sour with an API gravity of 23.5°. Assume that the refinery purchases at arm's length oil (all of which must be Wyoming general sour) in the following volumes of the API gravities stated at the prices and locations indicated:
10,000 bbl | 24.5° | $34.70/bbl | Purchased in the field.
8,000 bbl | 24.0° | 34.00/bbl | Purchased at the refinery after the third-party producer transported it to the refinery, and the lessee does not know the transportation costs.
9,000 bbl | 23.0° | 33.25/bbl | Purchased in the field.
| 4,000 bbl | 22.0° | 33.00/bbl | Purchased in the field.
2. Because the lessee does not know the costs that the seller of the 8,000 bbl incurred to transport that volume to the refinery, that volume will not be included in the volume-weighted average price calculation. Further assume that the gravity adjustment scale provides for a deduction of $0.02 per 1/10 degree API gravity below 34°. Normalized to 23.5° (the gravity of the oil being valued under this section), the prices of each of the volumes that the refiner purchased that are included in the volume-weighted average calculation are as follows:
10,000 bbl | 24.5° | $34.50 | (1.0° difference over 23.5° = $0.20 deducted).
9,000 bbl | 23.0° | 33.35 | (0.5° difference under 23.5° = $0.10 added).
4,000 bbl | 22.0° | 33.30 | (1.5° difference under 23.5° = $0.30 added).
3. The volume-weighted average price is ((10,000 bbl × $34.50/bbl) + (9,000 bbl × $33.35/bbl) + (4,000 bbl × $33.30/bbl)) / 23,000 bbl = $33.84/bbl. That price will be the value of the oil produced from the lease and refined prior to an arm's-length sale, under this section.
(c) If you value oil under this section, MMS will allow a deduction, under §§ 206.56 and 206.57, for the reasonable, actual costs:
(1) That you incur to transport oil that you or your affiliate sell(s), which is included in the weighted-average price calculation, from the lease to the point where the oil is sold; and
(2) That the seller incurs to transport oil that you or your affiliate purchase(s), which is included in the weighted-average cost calculation, from the property where it is produced to the point where you or your affiliate purchase(s) it. You may not deduct any costs of gathering as part of a transportation deduction or allowance.
(d) If paragraphs (a) and (b) of this section result in an unreasonable value for your production as a result of circumstances regarding that production, the MMS Director may establish an alternative valuation method.
(e) You must also comply with § 206.54.
[72 FR 71241, Dec. 17, 2007]
§ 206.54
How do I fulfill the lease provision regarding valuing production on the basis of the major portion of like-quality oil?
(a) For any Indian leases that provide that the Secretary may consider the highest price paid or offered for a major portion of production (major portion) in determining value for royalty purposes, if data are available to compute a major portion, MMS will, where practicable, compare the value determined in accordance with this section with the major portion. The value to be used in determining the value of production, for royalty purposes, will be the higher of those two values.
(b) For purposes of this paragraph, major portion means the highest price paid or offered at the time of production for the major portion of oil production from the same field. The major portion will be calculated using like-quality oil sold under arm's-length contracts from the same field (or, if necessary to obtain a reasonable sample, from the same area) for each month. All such oil production will be arrayed from highest price to lowest price (at the bottom). The major portion is that price at which 50 percent by volume plus one barrel of oil (starting from the bottom) is sold.
[72 FR 71241, Dec. 17, 2007]
§ 206.55
What are my responsibilities to place production into marketable condition and to market the production?
You must place oil in marketable condition and market the oil for the mutual benefit of yourself and the Indian lessor at no cost to the lessor, unless the lease agreement provides otherwise. If, in the process of marketing the oil or placing it in marketable condition, your gross proceeds are reduced because services are performed on your behalf that would be your responsibility, and if you valued the oil using your or your affiliate's gross proceeds (or gross proceeds received in the sale of oil received in exchange) under § 206.52, you must increase value to the extent that your gross proceeds are reduced.
[72 FR 71241, Dec. 17, 2007]
§ 206.56
Transportation allowances—general.
(a) Where the value of oil has been determined under § 206.52 or § 206.53 of this subpart at a point (e.g., sales point or point of value determination) off the lease, MMS shall allow a deduction for the reasonable, actual costs incurred by the lessee to transport oil to a point off the lease; provided, however, that no transportation allowance will be granted for transporting oil taken as Royalty-In-Kind (RIK); or
(b)(1) Except as provided in paragraph (b)(2) of this section, the transportation allowance deduction on the basis of a sales type code may not exceed 50 percent of the value of the oil at the point of sale as determined under § 206.52 of this subpart. Transportation costs cannot be transferred between sales type codes or to other products.
(2) Upon request of a lessee, MMS may approve a transportation allowance deduction in excess of the limitation prescribed by paragraph (b)(1) of this section. The lessee must demonstrate that the transportation costs incurred in excess of the limitation prescribed in paragraph (b)(1) of this section were reasonable, actual, and necessary. An application for exception (using Form MMS-4393, Request to Exceed Regulatory Allowance Limitation) must contain all relevant and supporting documentation necessary for MMS to make a determination. Under no circumstances may the value, for royalty purposes, under any sales type code, be reduced to zero.
(c) Transportation costs must be allocated among all products produced and transported as provided in § 206.57. Transportation allowances for oil shall be expressed as dollars per barrel.
(d) If, after a review or audit, MMS determines that a lessee has improperly determined a transportation allowance authorized by this subpart, then the lessee will pay any additional royalties, plus interest determined in accordance with 30 CFR 218.54, or will be entitled to a credit without interest.
[61 FR 5455, Feb. 12, 1996. Redesignated and amended at 72 FR 71241, Dec. 17, 2007; 73 FR 15890, Mar. 26, 2008]
§ 206.57
Determination of transportation allowances.
(a) Arm's-length transportation contracts. (1)(i) For transportation costs incurred by a lessee under an arm's-length contract, the transportation allowance shall be the reasonable, actual costs incurred by the lessee for transporting oil under that contract, except as provided in paragraphs (a)(1)(ii) and (a)(1)(iii) of this section, subject to monitoring, review, audit, and adjustment. The lessee shall have the burden of demonstrating that its contract is arm's-length. Such allowances shall be subject to the provisions of paragraph (f) of this section. Before any deduction may be taken, the lessee must submit a completed page one of Form MMS-4110 (and Schedule 1), Oil Transportation Allowance Report, in accordance with paragraph (c)(1) of this section. A transportation allowance may be claimed retroactively for a period of not more than 3 months prior to the first day of the month that Form MMS-4110 is filed with MMS, unless MMS approves a longer period upon a showing of good cause by the lessee.
(ii) In conducting reviews and audits, MMS will examine whether the contract reflects more than the consideration actually transferred either directly or indirectly from the lessee to the transporter for the transportation. If the contract reflects more than the total consideration, then MMS may require that the transportation allowance be determined in accordance with paragraph (b) of this section.
(iii) If MMS determines that the consideration paid under an arm's-length transportation contract does not reflect the reasonable value of the transportation because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then MMS shall require that the transportation allowance be determined in accordance with paragraph (b) of this section. When MMS determines that the value of the transportation may be unreasonable, MMS will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's transportation costs.
(2)(i) If an arm's-length transportation contract includes more than one liquid product, and the transportation costs attributable to each product cannot be determined from the contract, then the total transportation costs shall be allocated in a consistent and equitable manner to each of the liquid products transported in the same proportion as the ratio of the volume of each product (excluding waste products which have no value) to the volume of all liquid products (excluding waste products which have no value). Except as provided in this paragraph, no allowance may be taken for the costs of transporting lease production which is not royalty-bearing without MMS approval.
(ii) Notwithstanding the requirements of paragraph (i), the lessee may propose to MMS a cost allocation method on the basis of the values of the products transported. MMS shall approve the method unless it determines that it is not consistent with the purposes of the regulations in this part.
(3) If an arm's-length transportation contract includes both gaseous and liquid products, and the transportation costs attributable to each product cannot be determined from the contract, the lessee shall propose an allocation procedure to MMS. The lessee may use the oil transportation allowance determined in accordance with its proposed allocation procedure until MMS issues its determination on the acceptability of the cost allocation. The lessee shall submit all available data to support its proposal. The initial proposal must be submitted by June 30, 1988 or within 3 months after the last day of the month for which the lessee requests a transportation allowance, whichever is later (unless MMS approves a longer period). MMS shall then determine the oil transportation allowance based upon the lessee's proposal and any additional information MMS deems necessary.
(4) Where the lessee's payments for transportation under an arm's-length contract are not on a dollar-per-unit basis, the lessee shall convert whatever consideration is paid to a dollar value equivalent for the purposes of this section.
(5) Where an arm's-length sales contract price, or a posted price, includes a provision whereby the listed price is reduced by a transportation factor, MMS will not consider the transportation factor to be a transportation allowance. The transportation factor may be used in determining the lessee's gross proceeds for the sale of the product. The transportation factor may not exceed 50 percent of the base price of the product without MMS approval.
(b) Non-arm's-length or no contract. (1) If a lessee has a non-arm's-length transportation contract or has no contract, including those situations where the lessee performs transportation services for itself, the transportation allowance will be based upon the lessee's reasonable, actual costs as provided in this paragraph. All transportation allowances deducted under a non-arms-length or no-contract situation are subject to monitoring, review, audit, and adjustment. Before any estimated or actual deduction may be taken, the lessee must submit a completed Form MMS-4110 in its entirety in accordance with paragraph (c)(2) of this section. A transportation allowance may be claimed retroactively for a period of not more than 3 months prior to the first day of the month that Form MMS-4110 is filed with MMS, unless MMS approves a longer period upon a showing of good cause by the lessee. MMS will monitor the allowance deductions to determine whether lessees are taking deductions that are reasonable and allowable. When necessary or appropriate, MMS may direct a lessee to modify its actual transportation allowance deduction.
(2) The transportation allowance for non-arms-length or no-contract situations shall be based upon the lessee's actual costs for transportation during the reporting period, including operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment in accordance with paragraph (b)(2)(iv)(A) of this section, or a cost equal to the initial capital investment in the transportation system multiplied by a rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) which are an integral part of the transportation system.
(i) Allowable operating expenses include: Operations supervision and engineering; operations labor; fuel; utilities; materials; ad valorem property taxes; rent; supplies; and any other directly allocable and attributable operating expense which the lessee can document.
(ii) Allowable maintenance expenses include: Maintenance of the transportation system; maintenance of equipment; maintenance labor; and other directly allocable and attributable maintenance expenses which the lessee can document.
(iii) Overhead directly attributable and allocable to the operation and maintenance of the transportation system is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses.
(iv) A lessee may use either depreciation or a return on depreciable capital investment. After a lessee has elected to use either method for a transportation system, the lessee may not later elect to change to the other alternative without approval of MMS.
(A) To compute depreciation, the lessee may elect to use either a straight-line depreciation method based on the life of equipment or on the life of the reserves which the transportation system services or on a unit-of-production method. After an election is made, the lessee may not change methods without MMS approval. A change in ownership of a transportation system shall not alter the depreciation schedule established by the original transporter/lessee for purposes of the allowance calculation. With or without a change in ownership, a transportation system shall be depreciated only once. Equipment shall not be depreciated below a reasonable salvage value.
(B) MMS shall allow as a cost an amount equal to the initial capital investment in the transportation system multiplied by the rate of return determined under paragraph (b)(2)(v) of this section. No allowance shall be provided for depreciation. This alternative shall apply only to transportation facilities first placed in service after March 1, 1988.
(v) The rate of return shall be the industrial rate associated with Standard and Poor's BBB rating. The rate of return shall be the monthly average rate as published in Standard and Poor's Bond Guide for the first month of the reporting period for which the allowance is applicable and shall be effective during the reporting period. The rate shall be redetermined at the beginning of each subsequent transportation allowance reporting period (which is determined under paragraph (c) of this section).
(3)(i) The deduction for transportation costs shall be determined on the basis of the lessee's cost of transporting each product through each individual transportation system. Where more than one liquid product is transported, allocation of costs to each of the liquid products transported shall be in the same proportion as the ratio of the volume of each liquid product (excluding waste products which have no value) to the volume of all liquid products (excluding waste products which have no value) and such allocation shall be made in a consistent and equitable manner. Except as provided in this paragraph, the lessee may not take an allowance for transporting lease production which is not royalty-bearing without MMS approval.
(ii) Notwithstanding the requirements of paragraph (i), the lessee may propose to MMS a cost allocation method on the basis of the values of the products transported. MMS shall approve the method unless it determines that it is not consistent with the purposes of the regulations in this part.
(4) Where both gaseous and liquid products are transported through the same transportation system, the lessee shall propose a cost allocation procedure to MMS. The lessee may use the oil transportation allowance determined in accordance with its proposed allocation procedure until MMS issues its determination on the acceptability of the cost allocation. The lessee shall submit all available data to support its proposal. The initial proposal must be submitted by June 30, 1988 or within 3 months after the last day of the month for which the lessee requests a transportation allowance, whichever is later (unless MMS approves a longer period). MMS shall then determine the oil transportation allowance on the basis of the lessee's proposal and any additional information MMS deems necessary.
(5) A lessee may apply to MMS for an exception from the requirement that it compute actual costs in accordance with paragraphs (b)(1) through (b)(4) of this section. MMS will grant the exception only if the lessee has a tariff for the transportation system approved by the Federal Energy Regulatory Commission (FERC) for Indian leases. MMS shall deny the exception request if it determines that the tariff is excessive as compared to arm's-length transportation charges by pipelines, owned by the lessee or others, providing similar transportation services in that area. If there are no arm's-length transportation charges, MMS shall deny the exception request if:
(i) No FERC cost analysis exists and the FERC has declined to investigate under MMS timely objections upon filing; and
(ii) the tariff significantly exceeds the lessee's actual costs for transportation as determined under this section.
(c) Reporting requirements—(1) Arm's-length contracts. (i) With the exception of those transportation allowances specified in paragraphs (c)(1)(v) and (c)(1)(vi) of this section, the lessee shall submit page one of the initial Form MMS-4110 (and Schedule 1), Oil Transportation Allowance Report, prior to, or at the same time as, the transportation allowance determined, under an arm's-length contract, is reported on Form MMS-2014, Report of Sales and Royalty Remittance. A Form MMS-4110 received by the end of the month that the Form MMS-2014 is due shall be considered to be timely received.
(ii) The initial Form MMS-4110 shall be effective for a reporting period beginning the month that the lessee is first authorized to deduct a transportation allowance and shall continue until the end of the calendar year, or until the applicable contract or rate terminates or is modified or amended, whichever is earlier.
(iii) After the initial reporting period and for succeeding reporting periods, lessees must submit page one of Form MMS-4110 (and Schedule 1) within 3 months after the end of the calendar year, or after the applicable contract or rate terminates or is modified or amended, whichever is earlier, unless MMS approves a longer period (during which period the lessee shall continue to use the allowance from the previous reporting period).
(iv) MMS may require that a lessee submit arm's-length transportation contracts, production agreements, operating agreements, and related documents. Documents shall be submitted within a reasonable time, as determined by MMS.
(v) Transportation allowances which are based on arm's-length contracts and which are in effect at the time these regulations become effective will be allowed to continue until such allowances terminate. For the purposes of this section, only those allowances that have been approved by MMS in writing shall qualify as being in effect at the time these regulations become effective.
(vi) MMS may establish, in appropriate circumstances, reporting requirements which are different from the requirements of this section.
(2) Non-arm's-length or no contract. (i) With the exception of those transportation allowances specified in paragraphs (c)(2)(v), (c)(2)(vii) and (c)(2)(viii) of this section, the lessee shall submit an initial Form MMS-4110 prior to, or at the same time as, the transportation allowance determined under a non-arm's-length contract or no-contract situation is reported on Form MMS-2014. A Form MMS-4110 received by the end of the month that the Form MMS-2014 is due shall be considered to be timely received. The initial report may be based upon estimated costs.
(ii) The initial Form MMS-4110 shall be effective for a reporting period beginning the month that the lessee first is authorized to deduct a transportation allowance and shall continue until the end of the calendar year, or until transportation under the non-arm's-length contract or the no-contract situation terminates, whichever is earlier.
(iii) For calendar-year reporting periods succeeding the initial reporting period, the lessee shall submit a completed Form MMS-4110 containing the actual costs for the previous reporting period. If oil transportation is continuing, the lessee shall include on Form MMS-4110 its estimated costs for the next calendar year. The estimated oil transportation allowance shall be based on the actual costs for the previous reporting period plus or minus any adjustments which are based on the lessee's knowledge of decreases or increases that will affect the allowance. MMS must receive the Form MMS-4110 within 3 months after the end of the previous reporting period, unless MMS approves a longer period (during which period the lessee shall continue to use the allowance from the previous reporting period).
(iv) For new transportation facilities or arrangements, the lessee's initial Form MMS-4110 shall include estimates of the allowable oil transportation costs for the applicable period. Cost estimates shall be based upon the most recently available operations data for the transportation system or, if such data are not available, the lessee shall use estimates based upon industry data for similar transportation systems.
(v) Non-arm's-length contract or no-contract transportation allowances which are in effect at the time these regulations become effective will be allowed to continue until such allowances terminate. For the purposes of this section, only those allowances that have been approved by MMS in writing shall qualify as being in effect at the time these regulations become effective.
(vi) Upon request by MMS, the lessee shall submit all data used to prepare its Form MMS-4110. The data shall be provided within a reasonable period of time, as determined by MMS.
(vii) MMS may establish, in appropriate circumstances, reporting requirements which are different from the requirements of this section.
(viii) If the lessee is authorized to use its FERC-approved tariff as its transportation cost in accordance with paragraph (b)(5) of this section, it shall follow the reporting requirements of paragraph (c)(1) of this section.
(3) MMS may establish reporting dates for individual lessees different from those specified in this subpart in order to provide more effective administration. Lessees will be notified of any change in their reporting period.
(4) Transportation allowances must be reported as a separate entry on Form MMS-2014, unless MMS approves a different reporting procedure.
(d) Interest assessments for incorrect or late reports and for failure to report. (1) If a lessee deducts a transportation allowance on its Form MMS-2014 without complying with the requirements of this section, the lessee shall pay interest only on the amount of such deduction until the requirements of this section are complied with. The lessee also shall repay the amount of any allowance which is disallowed by this section.
(2) If a lessee erroneously reports a transportation allowance which results in an underpayment of royalties, interest shall be paid on the amount of that underpayment.
(3) Interest required to be paid by this section shall be determined in accordance with 30 CFR 218.54.
(e) Adjustments. (1) If the actual transportation allowance is less than the amount the lessee has taken on Form MMS-2014 for each month during the allowance form reporting period, the lessee must pay additional royalties due plus interest computed under 30 CFR 218.54, retroactive to the first day of the first month the lessee is authorized to deduct a transportation allowance. If the actual transportation allowance is greater than the amount the lessee has taken on Form MMS-2014 for each month during the allowance form reporting period, the lessee will be entitled to a credit without interest.
(2) For lessees transporting production from Indian leases, the lessee must submit a corrected Form MMS-2014 to reflect actual costs, together with any payment, in accordance with instructions provided by MMS.
(f) Actual or theoretical losses. Notwithstanding any other provisions of this subpart, for other than arm's-length contracts, no cost shall be allowed for oil transportation which results from payments (either volumetric or for value) for actual or theoretical losses. This section does not apply when the transportation allowance is based upon a FERC or State regulatory agency approved tariff.
(g) Other transportation cost determinations. The provisions of this section shall apply to determine transportation costs when establishing value using a netback valuation procedure or any other procedure that requires deduction of transportation costs.
[61 FR 5455, Feb. 12, 1996. Redesignated at 72 FR 71241, Dec. 17, 2007, as amended at 73 FR 15890, Mar. 26, 2008]
§ 206.58
What must I do if MMS finds that I have not properly determined value?
(a) If MMS finds that you have not properly determined value, you must:
(1) Pay the difference, if any, between the royalty payments you made and those that are due, based upon the value MMS establishes; and
(2) Pay interest on the difference computed under § 218.54 of this chapter.
(b) If you are entitled to a credit due to overpayment on Indian leases, see § 218.53 of this chapter. The credit will be without interest.
[72 FR 71244, Dec. 17, 2007]
§ 206.59
May I ask MMS for valuation guidance?
You may ask MMS for guidance in determining value. You may propose a value method to MMS. Submit all available data related to your proposal and any additional information MMS deems necessary. We will promptly review your proposal and provide you with non-binding guidance.
[72 FR 71244, Dec. 17, 2007]
§ 206.60
What are the quantity and quality bases for royalty settlement?
(a) You must compute royalties on the quantity and quality of oil as measured at the point of settlement approved by BLM for the lease.
(b) If you determine the value of oil under §§ 206.52, 206.53, or 206.54 of this subpart based on a quantity or quality different from the quantity or quality at the point of royalty settlement approved by BLM for the lease, you must adjust the value for those quantity or quality differences.
(c) You may not deduct from the royalty volume or royalty value actual or theoretical losses incurred before the royalty settlement point unless BLM determines that any actual loss was unavoidable.
[72 FR 71244, Dec. 17, 2007]
§ 206.61
What records must I keep and produce?
(a) On request, you must make available sales, volume, and transportation data for production you sold, purchased, or obtained from the field or area. You must make this data available to MMS, Indian representatives, or other authorized persons.
(b) You must retain all data relevant to the determination of royalty value. Document retention and recordkeeping requirements are found at §§ 207.5, 212.50, and 212.51 of this chapter. The MMS, Indian representatives, or other authorized persons may review and audit such data you possess, and MMS will direct you to use a different value if it determines that the reported value is inconsistent with the requirements of this subpart or the lease.
[72 FR 71244, Dec. 17, 2007]
§ 206.62
Does MMS protect information I provide?
The MMS will keep confidential, to the extent allowed under applicable laws and regulations, any data or other information you submit that is privileged, confidential, or otherwise exempt from disclosure. All requests for information must be submitted under the Freedom of Information Act regulations of the Department of the Interior, 43 CFR part 2.
[72 FR 71244, Dec. 17, 2007]

Subpart C—Federal Oil

Source:
65 FR 14088, Mar. 15, 2000, unless otherwise noted.
§ 206.100
What is the purpose of this subpart?
(a) This subpart applies to all oil produced from Federal oil and gas leases onshore and on the Outer Continental Shelf (OCS). It explains how you as a lessee must calculate the value of production for royalty purposes consistent with the mineral leasing laws, other applicable laws, and lease terms.
(b) If you are a designee and if you dispose of production on behalf of a lessee, the terms “you” and “your” in this subpart refer to you and not to the lessee. In this circumstance, you must determine and report royalty value for the lessee's oil by applying the rules in this subpart to your disposition of the lessee's oil.
(c) If you are a designee and only report for a lessee, and do not dispose of the lessee's production, references to “you” and “your” in this subpart refer to the lessee and not the designee. In this circumstance, you as a designee must determine and report royalty value for the lessee's oil by applying the rules in this subpart to the lessee's disposition of its oil.
(d) If the regulations in this subpart are inconsistent with:
(1) A Federal statute;
(2) A settlement agreement between the United States and a lessee resulting from administrative or judicial litigation;
(3) A written agreement between the lessee and the MMS Director establishing a method to determine the value of production from any lease that MMS expects at least would approximate the value established under this subpart; or
(4) An express provision of an oil and gas lease subject to this subpart, then the statute, settlement agreement, written agreement, or lease provision will govern to the extent of the inconsistency.
(e) MMS may audit and adjust all royalty payments.
§ 206.101
What definitions apply to this subpart?
The following definitions apply to this subpart:
Affiliate means a person who controls, is controlled by, or is under common control with another person. For purposes of this subpart:
(1) Ownership or common ownership of more than 50 percent of the voting securities, or instruments of ownership, or other forms of ownership, of another person constitutes control. Ownership of less than 10 percent constitutes a presumption of noncontrol that MMS may rebut.
(2) If there is ownership or common ownership of 10 through 50 percent of the voting securities or instruments of ownership, or other forms of ownership, of another person, MMS will consider the following factors in determining whether there is control under the circumstances of a particular case:
(i) The extent to which there are common officers or directors;
(ii) With respect to the voting securities, or instruments of ownership, or other forms of ownership: the percentage of ownership or common ownership, the relative percentage of ownership or common ownership compared to the percentage(s) of ownership by other persons, whether a person is the greatest single owner, or whether there is an opposing voting bloc of greater ownership;
(iii) Operation of a lease, plant, or other facility;
(iv) The extent of participation by other owners in operations and day-to-day management of a lease, plant, or other facility; and
(v) Other evidence of power to exercise control over or common control with another person.
(3) Regardless of any percentage of ownership or common ownership, relatives, either by blood or marriage, are affiliates.
ANS means Alaska North Slope (ANS).
Area means a geographic region at least as large as the limits of an oil field, in which oil has similar quality, economic, and legal characteristics.
Arm's-length contract means a contract or agreement between independent persons who are not affiliates and who have opposing economic interests regarding that contract. To be considered arm's length for any production month, a contract must satisfy this definition for that month, as well as when the contract was executed.
Audit means a review, conducted under generally accepted accounting and auditing standards, of royalty payment compliance activities of lessees, designees or other persons who pay royalties, rents, or bonuses on Federal leases.
BLM means the Bureau of Land Management of the Department of the Interior.
Condensate means liquid hydrocarbons (normally exceeding 40 degrees of API gravity) recovered at the surface without processing. Condensate is the mixture of liquid hydrocarbons resulting from condensation of petroleum hydrocarbons existing initially in a gaseous phase in an underground reservoir.
Contract means any oral or written agreement, including amendments or revisions, between two or more persons, that is enforceable by law and that with due consideration creates an obligation.
Designee means the person the lessee designates to report and pay the lessee's royalties for a lease.
Exchange agreement means an agreement where one person agrees to deliver oil to another person at a specified location in exchange for oil deliveries at another location. Exchange agreements may or may not specify prices for the oil involved. They frequently specify dollar amounts reflecting location, quality, or other differentials. Exchange agreements include buy/sell agreements, which specify prices to be paid at each exchange point and may appear to be two separate sales within the same agreement. Examples of other types of exchange agreements include, but are not limited to, exchanges of produced oil for specific types of crude oil (e.g., West Texas Intermediate); exchanges of produced oil for other crude oil at other locations (Location Trades); exchanges of produced oil for other grades of oil (Grade Trades); and multi-party exchanges.
Field means a geographic region situated over one or more subsurface oil and gas reservoirs and encompassing at least the outermost boundaries of all oil and gas accumulations known within those reservoirs, vertically projected to the land surface. State oil and gas regulatory agencies usually name onshore fields and designate their official boundaries. MMS names and designates boundaries of OCS fields.
Gathering means the movement of lease production to a central accumulation or treatment point on the lease, unit, or communitized area, or to a central accumulation or treatment point off the lease, unit, or communitized area that BLM or MMS approves for onshore and offshore leases, respectively.
Gross proceeds means the total monies and other consideration accruing for the disposition of oil produced. Gross proceeds also include, but are not limited to, the following examples:
(1) Payments for services such as dehydration, marketing, measurement, or gathering which the lessee must perform at no cost to the Federal Government;
(2) The value of services, such as salt water disposal, that the producer normally performs but that the buyer performs on the producer's behalf;
(3) Reimbursements for harboring or terminaling fees;
(4) Tax reimbursements, even though the Federal royalty interest may be exempt from taxation;
(5) Payments made to reduce or buy down the purchase price of oil to be produced in later periods, by allocating such payments over the production whose price the payment reduces and including the allocated amounts as proceeds for the production as it occurs; and
(6) Monies and all other consideration to which a seller is contractually or legally entitled, but does not seek to collect through reasonable efforts.
Lease means any contract, profit-share arrangement, joint venture, or other agreement issued or approved by the United States under a mineral leasing law that authorizes exploration for, development or extraction of, or removal of oil or gas—or the land area covered by that authorization, whichever the context requires.
Lessee means any person to whom the United States issues an oil and gas lease, an assignee of all or a part of the record title interest, or any person to whom operating rights in a lease have been assigned.
Location differential means an amount paid or received (whether in money or in barrels of oil) under an exchange agreement that results from differences in location between oil delivered in exchange and oil received in the exchange. A location differential may represent all or part of the difference between the price received for oil delivered and the price paid for oil received under a buy/sell exchange agreement.
Market center means a major point MMS recognizes for oil sales, refining, or transshipment. Market centers generally are locations where MMS-approved publications publish oil spot prices.
Marketable condition means oil sufficiently free from impurities and otherwise in a condition a purchaser will accept under a sales contract typical for the field or area.
MMS-approved publication means a publication MMS approves for determining ANS spot prices or WTI differentials.
Netting means reducing the reported sales value to account for transportation instead of reporting a transportation allowance as a separate entry on Form MMS-2014.
NYMEX price means the average of the New York Mercantile Exchange (NYMEX) settlement prices for light sweet crude oil delivered at Cushing, Oklahoma, calculated as follows:
(1) Sum the prices published for each day during the calendar month of production (excluding weekends and holidays) for oil to be delivered in the prompt month corresponding to each such day; and
(2) Divide the sum by the number of days on which those prices are published (excluding weekends and holidays).
Oil means a mixture of hydrocarbons that existed in the liquid phase in natural underground reservoirs, remains liquid at atmospheric pressure after passing through surface separating facilities, and is marketed or used as a liquid. Condensate recovered in lease separators or field facilities is oil.
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) and of which the subsoil and seabed appertain to the United States and are subject to its jurisdiction and control.
Person means any individual, firm, corporation, association, partnership, consortium, or joint venture (when established as a separate entity).
Prompt month means the nearest month of delivery for which NYMEX futures prices are published during the trading month.
Quality differential means an amount paid or received under an exchange agreement (whether in money or in barrels of oil) that results from differences in API gravity, sulfur content, viscosity, metals content, and other quality factors between oil delivered and oil received in the exchange. A quality differential may represent all or part of the difference between the price received for oil delivered and the price paid for oil received under a buy/sell agreement.
Rocky Mountain Region means the States of Colorado, Montana, North Dakota, South Dakota, Utah, and Wyoming, except for those portions of the San Juan Basin and other oil-producing fields in the “Four Corners” area that lie within Colorado and Utah.
Roll means an adjustment to the NYMEX price that is calculated as follows:
Roll = .6667 × (P0−P1) + .3333 × (P0−P2), where: P0 = the average of the daily NYMEX settlement prices for deliveries during the prompt month that is the same as the month of production, as published for each day during the trading month for which the month of production is the prompt month; P1 = the average of the daily NYMEX settlement prices for deliveries during the month following the month of production, published for each day during the trading month for which the month of production is the prompt month; and P2 = the average of the daily NYMEX settlement prices for deliveries during the second month following the month of production, as published for each day during the trading month for which the month of production is the prompt month. Calculate the average of the daily NYMEX settlement prices using only the days on which such prices are published (excluding weekends and holidays).
(1) Example 1. Prices in Out Months are Lower Going Forward: The month of production for which you must determine royalty value is March. March was the prompt month (for year 2003) from January 22 through February 20. April was the first month following the month of production, and May was the second month following the month of production. P0 therefore is the average of the daily NYMEX settlement prices for deliveries during March published for each business day between January 22 and February 20. P1 is the average of the daily NYMEX settlement prices for deliveries during April published for each business day between January 22 and February 20. P2 is the average of the daily NYMEX settlement prices for deliveries during May published for each business day between January 22 and February 20. In this example, assume that P0 = $28.00 per bbl, P1 = $27.70 per bbl, and P2 = $27.10 per bbl. In this example (a declining market), Roll = .6667 × ($28.00−$27.70) + .3333 × ($28.00−$27.10) = $.20 + $.30 = $.50. You add this number to the NYMEX price.
(2) Example 2. Prices in Out Months are Higher Going Forward: The month of production for which you must determine royalty value is July. July 2003 was the prompt month from May 21 through June 20. August was the first month following the month of production, and September was the second month following the month of production. P0 therefore is the average of the daily NYMEX settlement prices for deliveries during July published for each business day between May 21 and June 20. P1 is the average of the daily NYMEX settlement prices for deliveries during August published for each business day between May 21 and June 20. P2 is the average of the daily NYMEX settlement prices for deliveries during September published for each business day between May 21 and June 20. In this example, assume that P0 = $28.00 per bbl, P1 = $28.90 per bbl, and P2 = $29.50 per bbl. In this example (a rising market), Roll = .6667 × ($28.00−$28.90) + .3333 × ($28.00−$29.50) = (−$.60) + (−$.50) = −$1.10. You add this negative number to the NYMEX price (effectively a subtraction from the NYMEX price).
Sale means a contract between two persons where:
(1) The seller unconditionally transfers title to the oil to the buyer and does not retain any related rights such as the right to buy back similar quantities of oil from the buyer elsewhere;
(2) The buyer pays money or other consideration for the oil; and
(3) The parties' intent is for a sale of the oil to occur.
Spot price means the price under a spot sales contract where:
(1) A seller agrees to sell to a buyer a specified amount of oil at a specified price over a specified period of short duration;
(2) No cancellation notice is required to terminate the sales agreement; and
(3) There is no obligation or implied intent to continue to sell in subsequent periods.
Tendering program means a producer's offer of a portion of its crude oil produced from a field or area for competitive bidding, regardless of whether the production is offered or sold at or near the lease or unit or away from the lease or unit.
Trading month means the period extending from the second business day before the 25th day of the second calendar month preceding the delivery month (or, if the 25th day of that month is a non-business day, the second business day before the last business day preceding the 25th day of that month) through the third business day before the 25th day of the calendar month preceding the delivery month (or, if the 25th day of that month is a non-business day, the third business day before the last business day preceding the 25th day of that month), unless the NYMEX publishes a different definition or different dates on its official Web site, www.nymex.com, in which case the NYMEX definition will apply.
Transportation allowance means a deduction in determining royalty value for the reasonable, actual costs of moving oil to a point of sale or delivery off the lease, unit area, or communitized area. The transportation allowance does not include gathering costs.
WTI differential means the average of the daily mean differentials for location and quality between a grade of crude oil at a market center and West Texas Intermediate (WTI) crude oil at Cushing published for each day for which price publications perform surveys for deliveries during the production month, calculated over the number of days on which those differentials are published (excluding weekends and holidays). Calculate the daily mean differentials by averaging the daily high and low differentials for the month in the selected publication. Use only the days and corresponding differentials for which such differentials are published.
(1) Example. Assume the production month was March 2003. Industry trade publications performed their price surveys and determined differentials during January 26 through February 25 for oil delivered in March. The WTI differential (for example, the West Texas Sour crude at Midland, Texas, spread versus WTI) applicable to valuing oil produced in the March 2003 production month would be determined using all the business days for which differentials were published during the period January 26 through February 25 excluding weekends and holidays (22 days). To calculate the WTI differential, add together all of the daily mean differentials published for January 26 through February 25 and divide that sum by 22.
(2) [Reserved]
[65 FR 14088, Mar. 15, 2000, as amended at 69 FR 24975, May 5, 2004]
§ 206.102
How do I calculate royalty value for oil that I or my affiliate sell(s) under an arm's-length contract?
(a) The value of oil under this section is the gross proceeds accruing to the seller under the arm's-length contract, less applicable allowances determined under §§ 206.110 or 206.111. This value does not apply if you exercise an option to use a different value provided in paragraph (d)(1) or (d)(2)(i) of this section, or if one of the exceptions in paragraph (c) of this section applies. Use this paragraph (a) to value oil that:
(1) You sell under an arm's-length sales contract; or
(2) You sell or transfer to your affiliate or another person under a non-arm's-length contract and that affiliate or person, or another affiliate of either of them, then sells the oil under an arm's-length contract, unless you exercise the option provided in paragraph (d)(2)(i) of this section.
(b) If you have multiple arm's-length contracts to sell oil produced from a lease that is valued under paragraph (a) of this section, the value of the oil is the volume-weighted average of the values established under this section for each contract for the sale of oil produced from that lease.
(c) This paragraph contains exceptions to the valuation rule in paragraph (a) of this section. Apply these exceptions on an individual contract basis.
(1) In conducting reviews and audits, if MMS determines that any arm's-length sales contract does not reflect the total consideration actually transferred either directly or indirectly from the buyer to the seller, MMS may require that you value the oil sold under that contract either under § 206.103 or at the total consideration received.
(2) You must value the oil under § 206.103 if MMS determines that the value under paragraph (a) of this section does not reflect the reasonable value of the production due to either:
(i) Misconduct by or between the parties to the arm's-length contract; or
(ii) Breach of your duty to market the oil for the mutual benefit of yourself and the lessor.
(A) MMS will not use this provision to simply substitute its judgment of the market value of the oil for the proceeds received by the seller under an arm's-length sales contract.
(B) The fact that the price received by the seller under an arm's length contract is less than other measures of market price, such as index prices, is insufficient to establish breach of the duty to market unless MMS finds additional evidence that the seller acted unreasonably or in bad faith in the sale of oil from the lease.
(d)(1) If you enter into an arm's-length exchange agreement, or multiple sequential arm's-length exchange agreements, and following the exchange(s) you or your affiliate sell(s) the oil received in the exchange(s) under an arm's-length contract, then you may use either § 206.102(a) or § 206.103 to value your production for royalty purposes.
(i) If you use § 206.102(a), your gross proceeds are the gross proceeds under your or your affiliate's arm's-length sales contract after the exchange(s) occur(s). You must adjust your gross proceeds for any location or quality differential, or other adjustments, you received or paid under the arm's-length exchange agreement(s). If MMS determines that any arm's-length exchange agreement does not reflect reasonable location or quality differentials, MMS may require you to value the oil under § 206.103. You may not otherwise use the price or differential specified in an arm's-length exchange agreement to value your production.
(ii) When you elect under § 206.102(d)(1) to use § 206.102(a) or § 206.103, you must make the same election for all of your production from the same unit, communitization agreement, or lease (if the lease is not part of a unit or communitization agreement) sold under arm's-length contracts following arm's-length exchange agreements. You may not change your election more often than once every 2 years.
(2)(i) If you sell or transfer your oil production to your affiliate and that affiliate or another affiliate then sells the oil under an arm's-length contract, you may use either § 206.102(a) or § 206.103 to value your production for royalty purposes.
(ii) When you elect under § 206.102(d)(2)(i) to use § 206.102(a) or § 206.103, you must make the same election for all of your production from the same unit, communitization agreement, or lease (if the lease is not part of a unit or communitization agreement) that your affiliates resell at arm's length. You may not change your election more often than once every 2 years.
(e) If you value oil under paragraph (a) of this section:
(1) MMS may require you to certify that your or your affiliate's arm's-length contract provisions include all of the consideration the buyer must pay, either directly or indirectly, for the oil.
(2) You must base value on the highest price the seller can receive through legally enforceable claims under the contract.
(i) If the seller fails to take proper or timely action to receive prices or benefits it is entitled to, you must pay royalty at a value based upon that obtainable price or benefit. But you will owe no additional royalties unless or until the seller receives monies or consideration resulting from the price increase or additional benefits, if:
(A) The seller makes timely application for a price increase or benefit allowed under the contract;
(B) The purchaser refuses to comply; and
(C) The seller takes reasonable documented measures to force purchaser compliance.
(ii) Paragraph (e)(2)(i) of this section will not permit you to avoid your royalty payment obligation where a purchaser fails to pay, pays only in part, or pays late. Any contract revisions or amendments that reduce prices or benefits to which the seller is entitled must be in writing and signed by all parties to the arm's-length contract.
§ 206.103
How do I value oil that is not sold under an arm's-length contract?
This section explains how to value oil that you may not value under § 206.102 or that you elect under § 206.102(d) to value under this section. First determine whether paragraph (a), (b), or (c) of this section applies to production from your lease, or whether you may apply paragraph (d) or (e) with MMS approval.
(a) Production from leases in California or Alaska. Value is the average of the daily mean ANS spot prices published in any MMS-approved publication during the trading month most concurrent with the production month. (For example, if the production month is June, compute the average of the daily mean prices using the daily ANS spot prices published in the MMS-approved publication for all the business days in June.)
(1) To calculate the daily mean spot price, average the daily high and low prices for the month in the selected publication.
(2) Use only the days and corresponding spot prices for which such prices are published.
(3) You must adjust the value for applicable location and quality differentials, and you may adjust it for transportation costs, under § 206.112.
(4) After you select an MMS-approved publication, you may not select a different publication more often than once every 2 years, unless the publication you use is no longer published or MMS revokes its approval of the publication. If you are required to change publications, you must begin a new 2-year period.
(b) Production from leases in the Rocky Mountain Region. This paragraph provides methods and options for valuing your production under different factual situations. You must consistently apply paragraph (b)(1), (b)(2), or (b)(3) of this section to value all of your production from the same unit, communitization agreement, or lease (if the lease or a portion of the lease is not part of a unit or communitization agreement) that you cannot value under § 206.102 or that you elect under § 206.102(d) to value under this section.
(1) If you have an MMS-approved tendering program, you must value oil produced from leases in the area the tendering program covers at the highest winning bid price for tendered volumes.
(i) The minimum requirements for MMS to approve your tendering program are:
(A) You must offer and sell at least 30 percent of your or your affiliates' production from both Federal and non-Federal leases in the area under your tendering program; and
(B) You must receive at least three bids for the tendered volumes from bidders who do not have their own tendering programs that cover some or all of the same area.
(ii) If you do not have an MMS-approved tendering program, you may elect to value your oil under either paragraph (b)(2) or (b)(3) of this section. After you select either paragraph (b)(2) or (b)(3) of this section, you may not change to the other method more often than once every 2 years, unless the method you have been using is no longer applicable and you must apply the other paragraph. If you change methods, you must begin a new 2-year period.
(2) Value is the volume-weighted average of the gross proceeds accruing to the seller under your or your affiliates' arm's-length contracts for the purchase or sale of production from the field or area during the production month.
(i) The total volume purchased or sold under those contracts must exceed 50 percent of your and your affiliates' production from both Federal and non-Federal leases in the same field or area during that month.
(ii) Before calculating the volume-weighted average, you must normalize the quality of the oil in your or your affiliates' arm's-length purchases or sales to the same gravity as that of the oil produced from the lease.
(3) Value is the NYMEX price (without the roll), adjusted for applicable location and quality differentials and transportation costs under § 206.112.
(4) If you demonstrate to MMS's satisfaction that paragraphs (b)(1) through (b)(3) of this section result in an unreasonable value for your production as a result of circumstances regarding that production, the MMS Director may establish an alternative valuation method.
(c) Production from leases not located in California, Alaska, or the Rocky Mountain Region. (1) Value is the NYMEX price, plus the roll, adjusted for applicable location and quality differentials and transportation costs under § 206.112.
(2) If the MMS Director determines that use of the roll no longer reflects prevailing industry practice in crude oil sales contracts or that the most common formula used by industry to calculate the roll changes, MMS may terminate or modify use of the roll under paragraph (c)(1) of this section at the end of each 2-year period following July 6, 2004, through notice published in the Federal Register not later than 60 days before the end of the 2-year period. MMS will explain the rationale for terminating or modifying the use of the roll in this notice.
(d) Unreasonable value. If MMS determines that the NYMEX price or ANS spot price does not represent a reasonable royalty value in any particular case, MMS may establish reasonable royalty value based on other relevant matters.
(e) Production delivered to your refinery and the NYMEX price or ANS spot price is an unreasonable value. (1) Instead of valuing your production under paragraph (a), (b), or (c) of this section, you may apply to the MMS Director to establish a value representing the market at the refinery if:
(i) You transport your oil directly to your or your affiliate's refinery, or exchange your oil for oil delivered to your or your affiliate's refinery; and
(ii) You must value your oil under this section at the NYMEX price or ANS spot price; and
(iii) You believe that use of the NYMEX price or ANS spot price results in an unreasonable royalty value.
(2) You must provide adequate documentation and evidence demonstrating the market value at the refinery. That evidence may include, but is not limited to:
(i) Costs of acquiring other crude oil at or for the refinery;
(ii) How adjustments for quality, location, and transportation were factored into the price paid for other oil;
(iii) Volumes acquired for and refined at the refinery; and
(iv) Any other appropriate evidence or documentation that MMS requires.
(3) If the MMS Director establishes a value representing market value at the refinery, you may not take an allowance against that value under § 206.112(b) unless it is included in the Director's approval.
[65 FR 14088, Mar. 15, 2002, as amended at 67 FR 19111, Apr. 18, 2002; 69 FR 24976, May 5, 2004]
§ 206.104
What publications are acceptable to MMS?
(a) MMS periodically will publish in the Federal Register a list of acceptable publications for the NYMEX price and ANS spot price based on certain criteria, including, but not limited to:
(1) Publications buyers and sellers frequently use;
(2) Publications frequently mentioned in purchase or sales contracts;
(3) Publications that use adequate survey techniques, including development of estimates based on daily surveys of buyers and sellers of crude oil, and, for ANS spot prices, buyers and sellers of ANS crude oil; and
(4) Publications independent from MMS, other lessors, and lessees.
(b) Any publication may petition MMS to be added to the list of acceptable publications.
(c) MMS will specify the tables you must use in the acceptable publications.
(d) MMS may revoke its approval of a particular publication if it determines that the prices or differentials published in the publication do not accurately represent NYMEX prices or differentials or ANS spot market prices or differentials.
[65 FR 14088, Mar. 15, 2000, as amended at 69 FR 24976, May 5, 2004]
§ 206.105
What records must I keep to support my calculations of value under this subpart?
If you determine the value of your oil under this subpart, you must retain all data relevant to the determination of royalty value.
(a) You must be able to show:
(1) How you calculated the value you reported, including all adjustments for location, quality, and transportation, and
(2) How you complied with these rules.
(b) Recordkeeping requirements are found at part 207 of this chapter.
(c) MMS may review and audit your data, and MMS will direct you to use a different value if it determines that the reported value is inconsistent with the requirements of this subpart.
§ 206.106
What are my responsibilities to place production into marketable condition and to market production?
You must place oil in marketable condition and market the oil for the mutual benefit of the lessee and the lessor at no cost to the Federal Government. If you use gross proceeds under an arm's-length contract in determining value, you must increase those gross proceeds to the extent that the purchaser, or any other person, provides certain services that the seller normally would be responsible to perform to place the oil in marketable condition or to market the oil.
§ 206.107
How do I request a value determination?
(a) You may request a value determination from MMS regarding any Federal lease oil production. Your request must:
(1) Be in writing;
(2) Identify specifically all leases involved, the record title or operating rights owners of those leases, and the designees for those leases;
(3) Completely explain all relevant facts. You must inform MMS of any changes to relevant facts that occur before we respond to your request;
(4) Include copies of all relevant documents;
(5) Provide your analysis of the issue(s), including citations to all relevant precedents (including adverse precedents); and
(6) Suggest your proposed valuation method.
(b) MMS will reply to requests expeditiously. MMS may either:
(1) Issue a value determination signed by the Assistant Secretary, Land and Minerals Management; or
(2) Issue a value determination by MMS; or
(3) Inform you in writing that MMS will not provide a value determination. Situations in which MMS typically will not provide any value determination include, but are not limited to:
(i) Requests for guidance on hypothetical situations; and
(ii) Matters that are the subject of pending litigation or administrative appeals.
(c)(1) A value determination signed by the Assistant Secretary, Land and Minerals Management, is binding on both you and MMS until the Assistant Secretary modifies or rescinds it.
(2) After the Assistant Secretary issues a value determination, you must make any adjustments in royalty payments that follow from the determination and, if you owe additional royalties, pay late payment interest under 30 CFR 218.54.
(3) A value determination signed by the Assistant Secretary is the final action of the Department and is subject to judicial review under 5 U.S.C. 701-706.
(d) A value determination issued by MMS is binding on MMS and delegated States with respect to the specific situation addressed in the determination unless the MMS (for MMS-issued value determinations) or the Assistant Secretary modifies or rescinds it.
(1) A value determination by MMS is not an appealable decision or order under 30 CFR part 290 subpart B.
(2) If you receive an order requiring you to pay royalty on the same basis as the value determination, you may appeal that order under 30 CFR part 290 subpart B.
(e) In making a value determination, MMS or the Assistant Secretary may use any of the applicable valuation criteria in this subpart.
(f) A change in an applicable statute or regulation on which any value determination is based takes precedence over the value determination, regardless of whether the MMS or the Assistant Secretary modifies or rescinds the value determination.
(g) The MMS or the Assistant Secretary generally will not retroactively modify or rescind a value determination issued under paragraph (d) of this section, unless:
(1) There was a misstatement or omission of material facts; or
(2) The facts subsequently developed are materially different from the facts on which the guidance was based.
(h) MMS may make requests and replies under this section available to the public, subject to the confidentiality requirements under § 206.108.
§ 206.108
Does MMS protect information I provide?
Certain information you submit to MMS regarding valuation of oil, including transportation allowances, may be exempt from disclosure. To the extent applicable laws and regulations permit, MMS will keep confidential any data you submit that is privileged, confidential, or otherwise exempt from disclosure. All requests for information must be submitted under the Freedom of Information Act regulations of the Department of the Interior at 43 CFR part 2.
§ 206.109
When may I take a transportation allowance in determining value?
(a) Transportation allowances permitted when value is based on gross proceeds. MMS will allow a deduction for the reasonable, actual costs to transport oil from the lease to the point off the lease under §§ 206.110 or 206.111, as applicable. This paragraph applies when:
(1) You value oil under § 206.102 based on gross proceeds from a sale at a point off the lease, unit, or communitized area where the oil is produced, and
(2) The movement to the sales point is not gathering.
(b) Transportation allowances and other adjustments that apply when value is based on NYMEX prices or ANS spot prices. If you value oil using NYMEX prices or ANS spot prices under § 206.103, MMS will allow an adjustment for certain location and quality differentials and certain costs associated with transporting oil as provided under § 206.112.
(c) Limits on transportation allowances. (1) Except as provided in paragraph (c)(2) of this section, your transportation allowance may not exceed 50 percent of the value of the oil as determined under § 206.102 or § 206.103 of this subpart. You may not use transportation costs incurred to move a particular volume of production to reduce royalties owed on production for which those costs were not incurred.
(2) You may ask MMS to approve a transportation allowance in excess of the limitation in paragraph (c)(1) of this section. You must demonstrate that the transportation costs incurred were reasonable, actual, and necessary. Your application for exception (using Form MMS-4393, Request to Exceed Regulatory Allowance Limitation) must contain all relevant and supporting documentation necessary for MMS to make a determination. You may never reduce the royalty value of any production to zero.
(d) Allocation of transportation costs. You must allocate transportation costs among all products produced and transported as provided in §§ 206.110 and 206.111. You must express transportation allowances for oil as dollars per barrel.
(e) Liability for additional payments. If MMS determines that you took an excessive transportation allowance, then you must pay any additional royalties due, plus interest under 30 CFR 218.54. You also could be entitled to a credit with interest under applicable rules if you understated your transportation allowance. If you take a deduction for transportation on Form MMS-2014 by improperly netting the allowance against the sales value of the oil instead of reporting the allowance as a separate entry, MMS may assess you an amount under § 206.116.
[65 FR 14088, Mar. 15, 2000, as amended at 69 FR 24976, May 5, 2004]
§ 206.110
How do I determine a transportation allowance under an arm's-length transportation contract?
(a) If you or your affiliate incur transportation costs under an arm's-length transportation contract, you may claim a transportation allowance for the reasonable, actual costs incurred as more fully explained in paragraph (b) of this section, except as provided in paragraphs (a)(1) and (a)(2) of this section and subject to the limitation in § 206.109(c). You must be able to demonstrate that your or your affiliate's contract is at arm's length. You do not need MMS approval before reporting a transportation allowance for costs incurred under an arm's-length transportation contract.
(1) If MMS determines that the contract reflects more than the consideration actually transferred either directly or indirectly from you or your affiliate to the transporter for the transportation, MMS may require that you calculate the transportation allowance under § 206.111.
(2) You must calculate the transportation allowance under § 206.111 if MMS determines that the consideration paid under an arm's-length transportation contract does not reflect the reasonable value of the transportation due to either:
(i) Misconduct by or between the parties to the arm's-length contract; or
(ii) Breach of your duty to market the oil for the mutual benefit of yourself and the lessor.
(A) MMS will not use this provision to simply substitute its judgment of the reasonable oil transportation costs incurred by you or your affiliate under an arm's-length transportation contract.
(B) The fact that the cost you or your affiliate incur in an arm's length transaction is higher than other measures of transportation costs, such as rates paid by others in the field or area, is insufficient to establish breach of the duty to market unless MMS finds additional evidence that you or your affiliate acted unreasonably or in bad faith in transporting oil from the lease.
(b) You may deduct any of the following actual costs you (including your affiliates) incur for transporting oil. You may not use as a deduction any cost that duplicates all or part of any other cost that you use under this paragraph.
(1) The amount that you pay under your arm's-length transportation contract or tariff.
(2) Fees paid (either in volume or in value) for actual or theoretical line losses.
(3) Fees paid for administration of a quality bank.
(4) The cost of carrying on your books as inventory a volume of oil that the pipeline operator requires you to maintain, and that you do maintain, in the line as line fill. You must calculate this cost as follows:
(i) Multiply the volume that the pipeline requires you to maintain, and that you do maintain, in the pipeline by the value of that volume for the current month calculated under § 206.102 or § 206.103, as applicable; and
(ii) Multiply the value calculated under paragraph (b)(4)(i) of this section by the monthly rate of return, calculated by dividing the rate of return specified in § 206.111(i)(2) by 12.
(5) Fees paid to a terminal operator for loading and unloading of crude oil into or from a vessel, vehicle, pipeline, or other conveyance.
(6) Fees paid for short-term storage (30 days or less) incidental to transportation as required by a transporter.
(7) Fees paid to pump oil to another carrier's system or vehicles as required under a tariff.
(8) Transfer fees paid to a hub operator associated with physical movement of crude oil through the hub when you do not sell the oil at the hub. These fees do not include title transfer fees.
(9) Payments for a volumetric deduction to cover shrinkage when high-gravity petroleum (generally in excess of 51 degrees API) is mixed with lower-gravity crude oil for transportation.
(10) Costs of securing a letter of credit, or other surety, that the pipeline requires you as a shipper to maintain.
(c) You may not deduct any costs that are not actual costs of transporting oil, including but not limited to the following:
(1) Fees paid for long-term storage (more than 30 days).
(2) Administrative, handling, and accounting fees associated with terminalling.
(3) Title and terminal transfer fees.
(4) Fees paid to track and match receipts and deliveries at a market center or to avoid paying title transfer fees.
(5) Fees paid to brokers.
(6) Fees paid to a scheduling service provider.
(7) Internal costs, including salaries and related costs, rent/space costs, office equipment costs, legal fees, and other costs to schedule, nominate, and account for sale or movement of production.
(8) Gauging fees.
(d) If your arm's-length transportation contract includes more than one liquid product, and the transportation costs attributable to each product cannot be determined from the contract, then you must allocate the total transportation costs to each of the liquid products transported.
(1) Your allocation must use the same proportion as the ratio of the volume of each product (excluding waste products with no value) to the volume of all liquid products (excluding waste products with no value).
(2) You may not claim an allowance for the costs of transporting lease production that is not royalty-bearing.
(3) You may propose to MMS a cost allocation method on the basis of the values of the products transported. MMS will approve the method unless it is not consistent with the purposes of the regulations in this subpart.
(e) If your arm's-length transportation contract includes both gaseous and liquid products, and the transportation costs attributable to each product cannot be determined from the contract, then you must propose an allocation procedure to MMS.
(1) You may use your proposed procedure to calculate a transportation allowance until MMS accepts or rejects your cost allocation. If MMS rejects your cost allocation, you must amend your Form MMS-2014 for the months that you used the rejected method and pay any additional royalty and interest due.
(2) You must submit your initial proposal, including all available data, within 3 months after first claiming the allocated deductions on Form MMS-2014.
(f) If your payments for transportation under an arm's-length contract are not on a dollar-per-unit basis, you must convert whatever consideration is paid to a dollar-value equivalent.
(g) If your arm's-length sales contract includes a provision reducing the contract price by a transportation factor, do not separately report the transportation factor as a transportation allowance on Form MMS-2014.
(1) You may use the transportation factor in determining your gross proceeds for the sale of the product.
(2) You must obtain MMS approval before claiming a transportation factor in excess of 50 percent of the base price of the product.
[65 FR 14088, Mar. 15, 2000, as amended at 69 FR 24976, May 5, 2004]
§ 206.111
How do I determine a transportation allowance if I do not have an arm's-length transportation contract or arm's-length tariff?
(a) This section applies if you or your affiliate do not have an arm's-length transportation contract, including situations where you or your affiliate provide your own transportation services. Calculate your transportation allowance based on your or your affiliate's reasonable, actual costs for transportation during the reporting period using the procedures prescribed in this section.
(b) Your or your affiliate's actual costs include the following:
(1) Operating and maintenance expenses under paragraphs (d) and (e) of this section;
(2) Overhead under paragraph (f) of this section;
(3) Depreciation under paragraphs (g) and (h) of this section;
(4) A return on undepreciated capital investment under paragraph (i) of this section; and
(5) Once the transportation system has been depreciated below ten percent of total capital investment, a return on ten percent of total capital investment under paragraph (j) of this section.
(6) To the extent not included in costs identified in paragraphs (d) through (j) of this section, you may also deduct the following actual costs. You may not use any cost as a deduction that duplicates all or part of any other cost that you use under this section:
(i) Volumetric adjustments for actual (not theoretical) line losses.
(ii) The cost of carrying on your books as inventory a volume of oil that the pipeline operator requires you as a shipper to maintain, and that you do maintain, in the line as line fill. You must calculate this cost as follows:
(A) Multiply the volume that the pipeline requires you to maintain, and that you do maintain, in the pipeline by the value of that volume for the current month calculated under § 206.102 or § 206.103, as applicable; and
(B) Multiply the value calculated under paragraph (b)(6)(ii)(A) of this section by the monthly rate of return, calculated by dividing the rate of return specified in § 206.111(i)(2) by 12.
(iii) Fees paid to a non-affiliated terminal operator for loading and unloading of crude oil into or from a vessel, vehicle, pipeline, or other conveyance.
(iv) Transfer fees paid to a hub operator associated with physical movement of crude oil through the hub when you do not sell the oil at the hub. These fees do not include title transfer fees.
(v) A volumetric deduction to cover shrinkage when high-gravity petroleum (generally in excess of 51 degrees API) is mixed with lower-gravity crude oil for transportation.
(vi) Fees paid to a non-affiliated quality bank administrator for administration of a quality bank.
(7) You may not deduct any costs that are not actual costs of transporting oil, including but not limited to the following:
(i) Fees paid for long-term storage (more than 30 days).
(ii) Administrative, handling, and accounting fees associated with terminalling.
(iii) Title and terminal transfer fees.
(iv) Fees paid to track and match receipts and deliveries at a market center or to avoid paying title transfer fees.
(v) Fees paid to brokers.
(vi) Fees paid to a scheduling service provider.
(vii) Internal costs, including salaries and related costs, rent/space costs, office equipment costs, legal fees, and other costs to schedule, nominate, and account for sale or movement of production.
(viii) Theoretical line losses.
(ix) Gauging fees.
(c) Allowable capital costs are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) which are an integral part of the transportation system.
(d) Allowable operating expenses include:
(i) Operations supervision and engineering;
(ii) Operations labor;
(iii) Fuel;
(iv) Utilities;
(v) Materials;
(vi) Ad valorem property taxes;
(vii) Rent;
(viii) Supplies; and
(ix) Any other directly allocable and attributable operating expense which you can document.
(e) Allowable maintenance expenses include:
(i) Maintenance of the transportation system;
(ii) Maintenance of equipment;
(iii) Maintenance labor; and
(iv) Other directly allocable and attributable maintenance expenses which you can document.
(f) Overhead directly attributable and allocable to the operation and maintenance of the transportation system is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses.
(g) To compute depreciation, you may elect to use either a straight-line depreciation method based on the life of equipment or on the life of the reserves which the transportation system services, or a unit-of-production method. After you make an election, you may not change methods without MMS approval. You may not depreciate equipment below a reasonable salvage value.
(h) This paragraph describes the basis for your depreciation schedule.
(1) If you or your affiliate own a transportation system on June 1, 2000, you must base your depreciation schedule used in calculating actual transportation costs for production after June 1, 2000, on your total capital investment in the system (including your original purchase price or construction cost and subsequent reinvestment).
(2) If you or your affiliate purchased the transportation system at arm's length before June 1, 2000, you must incorporate depreciation on the schedule based on your purchase price (and subsequent reinvestment) into your transportation allowance calculations for production after June 1, 2000, beginning at the point on the depreciation schedule corresponding to that date. You must prorate your depreciation for calendar year 2000 by claiming part-year depreciation for the period from June 1, 2000 until December 31, 2000. You may not adjust your transportation costs for production before June 1, 2000, using the depreciation schedule based on your purchase price.
(3) If you are the original owner of the transportation system on June 1, 2000, or if you purchased your transportation system before March 1, 1988, you must continue to use your existing depreciation schedule in calculating actual transportation costs for production in periods after June 1, 2000.
(4) If you or your affiliate purchase a transportation system at arm's length from the original owner after June 1, 2000, you must base your depreciation schedule used in calculating actual transportation costs on your total capital investment in the system (including your original purchase price and subsequent reinvestment). You must prorate your depreciation for the year in which you or your affiliate purchased the system to reflect the portion of that year for which you or your affiliate own the system.
(5) If you or your affiliate purchase a transportation system at arm's length after June 1, 2000, from anyone other than the original owner, you must assume the depreciation schedule of the person from whom you bought the system. Include in the depreciation schedule any subsequent reinvestment.
(i)(1) To calculate a return on undepreciated capital investment, multiply the remaining undepreciated capital balance as of the beginning of the period for which you are calculating the transportation allowance by the rate of return provided in paragraph (i)(2) of this section.
(2) The rate of return is 1.3 times the industrial bond yield index for Standard & Poor's BBB bond rating. Use the monthly average rate published in “Standard & Poor's Bond Guide” for the first month of the reporting period for which the allowance applies. Calculate the rate at the beginning of each subsequent transportation allowance reporting period.
(j)(1) After a transportation system has been depreciated at or below a value equal to ten percent of your total capital investment, you may continue to include in the allowance calculation a cost equal to ten percent of your total capital investment in the transportation system multiplied by a rate of return under paragraph (i)(2) of this section.
(2) You may apply this paragraph to a transportation system that before June 1, 2000, was depreciated at or below a value equal to ten percent of your total capital investment.
(k) Calculate the deduction for transportation costs based on your or your affiliate's cost of transporting each product through each individual transportation system. Where more than one liquid product is transported, allocate costs consistently and equitably to each of the liquid products transported. Your allocation must use the same proportion as the ratio of the volume of each liquid product (excluding waste products with no value) to the volume of all liquid products (excluding waste products with no value).
(1) You may not take an allowance for transporting lease production that is not royalty-bearing.
(2) You may propose to MMS a cost allocation method on the basis of the values of the products transported. MMS will approve the method if it is consistent with the purposes of the regulations in this subpart.
(l)(1) Where you transport both gaseous and liquid products through the same transportation system, you must propose a cost allocation procedure to MMS.
(2) You may use your proposed procedure to calculate a transportation allowance until MMS accepts or rejects your cost allocation. If MMS rejects your cost allocation, you must amend your Form MMS-2014 for the months that you used the rejected method and pay any additional royalty and interest due.
(3) You must submit your initial proposal, including all available data, within 3 months after first claiming the allocated deductions on Form MMS-2014.
[65 FR 14088, Mar. 15, 2000, as amended at 69 FR 24977, May 5, 2004]
§ 206.112
What adjustments and transportation allowances apply when I value oil production from my lease using NYMEX prices or ANS spot prices?
This section applies when you use NYMEX prices or ANS spot prices to calculate the value of production under § 206.103. As specified in this section, adjust the NYMEX price to reflect the difference in value between your lease and Cushing, Oklahoma, or adjust the ANS spot price to reflect the difference in value between your lease and the appropriate MMS-recognized market center at which the ANS spot price is published (for example, Long Beach, California, or San Francisco, California). Paragraph (a) of this section explains how you adjust the value between the lease and the market center, and paragraph (b) of this section explains how you adjust the value between the market center and Cushing when you use NYMEX prices. Paragraph (c) of this section explains how adjustments may be made for quality differentials that are not accounted for through exchange agreements. Paragraph (d) of this section gives some examples. References in this section to “you” include your affiliates as applicable.
(a) To adjust the value between the lease and the market center:
(1)(i) For oil that you exchange at arm's length between your lease and the market center (or between any intermediate points between those locations), you must calculate a lease-to-market center differential by the applicable location and quality differentials derived from your arm's-length exchange agreement applicable to production during the production month.
(ii) For oil that you exchange between your lease and the market center (or between any intermediate points between those locations) under an exchange agreement that is not at arm's length, you must obtain approval from MMS for a location and quality differential. Until you obtain such approval, you may use the location and quality differential derived from that exchange agreement applicable to production during the production month. If MMS prescribes a different differential, you must apply MMS's differential to all periods for which you used your proposed differential. You must pay any additional royalties owed resulting from using MMS's differential plus late payment interest from the original royalty due date, or you may report a credit for any overpaid royalties plus interest under 30 U.S.C. 1721(h).
(2) For oil that you transport between your lease and the market center (or between any intermediate points between those locations), you may take an allowance for the cost of transporting that oil between the relevant points as determined under § 206.110 or § 206.111, as applicable.
(3) If you transport or exchange at arm's length (or both transport and exchange) at least 20 percent, but not all, of your oil produced from the lease to a market center, determine the adjustment between the lease and the market center for the oil that is not transported or exchanged (or both transported and exchanged) to or through a market center as follows:
(i) Determine the volume-weighted average of the lease-to-market center adjustment calculated under paragraphs (a)(1) and (a)(2) of this section for the oil that you do transport or exchange (or both transport and exchange) from your lease to a market center.
(ii) Use that volume-weighted average lease-to-market center adjustment as the adjustment for the oil that you do not transport or exchange (or both transport and exchange) from your lease to a market center.
(4) If you transport or exchange (or both transport and exchange) less than 20 percent of the crude oil produced from your lease between the lease and a market center, you must propose to MMS an adjustment between the lease and the market center for the portion of the oil that you do not transport or exchange (or both transport and exchange) to a market center. Until you obtain such approval, you may use your proposed adjustment. If MMS prescribes a different adjustment, you must apply MMS's adjustment to all periods for which you used your proposed adjustment. You must pay any additional royalties owed resulting from using MMS's adjustment plus late payment interest from the original royalty due date, or you may report a credit for any overpaid royalties plus interest under 30 U.S.C. 1721(h).
(5) You may not both take a transportation allowance and use a location and quality adjustment or exchange differential for the same oil between the same points.
(b) For oil that you value using NYMEX prices, adjust the value between the market center and Cushing, Oklahoma, as follows:
(1) If you have arm's-length exchange agreements between the market center and Cushing under which you exchange to Cushing at least 20 percent of all the oil you own at the market center during the production month, you must use the volume-weighted average of the location and quality differentials from those agreements as the adjustment between the market center and Cushing for all the oil that you produce from the leases during that production month for which that market center is used.
(2) If paragraph (b)(1) of this section does not apply, you must use the WTI differential published in an MMS-approved publication for the market center nearest your lease, for crude oil most similar in quality to your production, as the adjustment between the market center and Cushing. (For example, for light sweet crude oil produced offshore of Louisiana, use the WTI differential for Light Louisiana Sweet crude oil at St. James, Louisiana.) After you select an MMS-approved publication, you may not select a different publication more often than once every 2 years, unless the publication you use is no longer published or MMS revokes its approval of the publication. If you are required to change publications, you must begin a new 2-year period.
(3) If neither paragraph (b)(1) nor (b)(2) of this section applies, you may propose an alternative differential to MMS. Until you obtain such approval, you may use your proposed differential. If MMS prescribes a different differential, you must apply MMS's differential to all periods for which you used your proposed differential. You must pay any additional royalties owed resulting from using MMS's differential plus late payment interest from the original royalty due date, or you may report a credit for any overpaid royalties plus interest under 30 U.S.C. 1721(h).
(c)(1) If you adjust for location and quality differentials or for transportation costs under paragraphs (a) and (b) of this section, also adjust the NYMEX price or ANS spot price for quality based on premiums or penalties determined by pipeline quality bank specifications at intermediate commingling points or at the market center if those points are downstream of the royalty measurement point approved by MMS or BLM, as applicable. Make this adjustment only if and to the extent that such adjustments were not already included in the location and quality differentials determined from your arm's-length exchange agreements.
(2) If the quality of your oil as adjusted is still different from the quality of the representative crude oil at the market center after making the quality adjustments described in paragraphs (a), (b) and (c)(1) of this section, you may make further gravity adjustments using posted price gravity tables. If quality bank adjustments do not incorporate or provide for adjustments for sulfur content, you may make sulfur adjustments, based on the quality of the representative crude oil at the market center, of 5.0 cents per one-tenth percent difference in sulfur content, unless MMS approves a higher adjustment.
(d) The examples in this paragraph illustrate how to apply the requirement of this section.
(1) Example. Assume that a Federal lessee produces crude oil from a lease near Artesia, New Mexico. Further, assume that the lessee transports the oil to Roswell, New Mexico, and then exchanges the oil to Midland, Texas. Assume the lessee refines the oil received in exchange at Midland. Assume that the NYMEX price is $30.00/bbl, adjusted for the roll; that the WTI differential (Cushing to Midland) is −$.10/bbl; that the lessee's exchange agreement between Roswell and Midland results in a location and quality differential of −$.08/bbl; and that the lessee's actual cost of transporting the oil from Artesia to Roswell is $.40/bbl. In this example, the royalty value of the oil is $30.00−$.10−$.08—$.40 = $29.42/bbl.
(2) Example. Assume the same facts as in the example in paragraph (1), except that the lessee transports and exchanges to Midland 40 percent of the production from the lease near Artesia, and transports the remaining 60 percent directly to its own refinery in Ohio. In this example, the 40 percent of the production would be valued at $29.42/bbl, as explained in the previous example. In this example, the other 60 percent also would be valued at $29.42/bbl.
(3) Example. Assume that a Federal lessee produces crude oil from a lease near Bakersfield, California. Further, assume that the lessee transports the oil to Hynes Station, and then exchanges the oil to Cushing which it further exchanges with oil it refines. Assume that the ANS spot price is $20.00/bbl, and that the lessee's actual cost of transporting the oil from Bakersfield to Hynes Station is $.28/bbl. The lessee must request approval from MMS for a location and quality adjustment between Hynes Station and Long Beach. For example, the lessee likely would propose using the tariff on Line 63 from Hynes Station to Long Beach as the adjustment between those points. Assume that adjustment to be $.72, including the sulfur and gravity bank adjustments, and that MMS approves the lessee's request. In this example, the preliminary (because the location and quality adjustment is subject to MMS review) royalty value of the oil is $20.00−$.72−$.28 = $19.00/bbl. The fact that oil was exchanged to Cushing does not change use of ANS spot prices for royalty valuation.
[69 FR 24978, May 5, 2004]
§ 206.113
How will MMS identify market centers?
MMS periodically will publish in the Federal Register a list of market centers. MMS will monitor market activity and, if necessary, add to or modify the list of market centers and will publish such modifications in the Federal Register. MMS will consider the following factors and conditions in specifying market centers:
(a) Points where MMS-approved publications publish prices useful for index purposes;
(b) Markets served;
(c) Input from industry and others knowledgeable in crude oil marketing and transportation;
(d) Simplification; and
(e) Other relevant matters.
§ 206.114
What are my reporting requirements under an arm's-length transportation contract?
You or your affiliate must use a separate entry on Form MMS-2014 to notify MMS of an allowance based on transportation costs you or your affiliate incur. MMS may require you or your affiliate to submit arm's-length transportation contracts, production agreements, operating agreements, and related documents. Recordkeeping requirements are found at part 207 of this chapter.
§ 206.115
What are my reporting requirements under a non-arm's-length transportation arrangement?
(a) You or your affiliate must use a separate entry on Form MMS-2014 to notify MMS of an allowance based on transportation costs you or your affiliate incur.
(b) For new transportation facilities or arrangements, base your initial deduction on estimates of allowable oil transportation costs for the applicable period. Use the most recently available operations data for the transportation system or, if such data are not available, use estimates based on data for similar transportation systems. Section 206.117 will apply when you amend your report based on your actual costs.
(c) MMS may require you or your affiliate to submit all data used to calculate the allowance deduction. Recordkeeping requirements are found at part 207 of this chapter.
§ 206.116
What interest applies if I improperly report a transportation allowance?
(a) If you or your affiliate deducts a transportation allowance on Form MMS-2014 that exceeds 50 percent of the value of the oil transported without obtaining MMS's prior approval under § 206.109, you must pay interest on the excess allowance amount taken from the date that amount is taken to the date you or your affiliate files an exception request that MMS approves. If you do not file an exception request, or if MMS does not approve your request, you must pay interest on the excess allowance amount taken from the date that amount is taken until the date you pay the additional royalties owed.
(b) If you or your affiliate takes a deduction for transportation on Form MMS-2014 by improperly netting an allowance against the oil instead of reporting the allowance as a separate entry, MMS may assess a civil penalty under 30 CFR part 241.
[73 FR 15890, Mar. 26, 2008]
§ 206.117
What reporting adjustments must I make for transportation allowances?
(a) If your or your affiliate's actual transportation allowance is less than the amount you claimed on Form MMS-2014 for each month during the allowance reporting period, you must pay additional royalties plus interest computed under 30 CFR 218.54 from the date you took the deduction to the date you repay the difference.
(b) If the actual transportation allowance is greater than the amount you claimed on Form MMS-2014 for any month during the allowance form reporting period, you are entitled to a credit plus interest under applicable rules.
§ 206.119
How are royalty quantity and quality determined?
(a) Compute royalties based on the quantity and quality of oil as measured at the point of settlement approved by BLM for onshore leases or MMS for offshore leases.
(b) If the value of oil determined under this subpart is based upon a quantity or quality different from the quantity or quality at the point of royalty settlement approved by the BLM for onshore leases or MMS for offshore leases, adjust the value for those differences in quantity or quality.
(c) Any actual loss that you may incur before the royalty settlement metering or measurement point is not subject to royalty if BLM or MMS, as appropriate, determines that the loss is unavoidable.
(d) Except as provided in paragraph (b) of this section, royalties are due on 100 percent of the volume measured at the approved point of royalty settlement. You may not claim a reduction in that measured volume for actual losses beyond the approved point of royalty settlement or for theoretical losses that are claimed to have taken place either before or after the approved point of royalty settlement.
[65 FR 14088, Mar. 15, 2000, as amended at 69 FR 24979, May 5, 2004]
§ 206.120
How are operating allowances determined?
MMS may use an operating allowance for the purpose of computing payment obligations when specified in the notice of sale and the lease. MMS will specify the allowance amount or formula in the notice of sale and in the lease agreement.

Subpart D—Federal Gas

Source:
53 FR 1272, Jan. 15, 1988, unless otherwise noted.
§ 206.150
Purpose and scope.
(a) This subpart is applicable to all gas production from Federal oil and gas leases. The purpose of this subpart is to establish the value of production for royalty purposes consistent with the mineral leasing laws, other applicable laws and lease terms.
(b) If the regulations in this subpart are inconsistent with:
(1) A Federal statute;
(2) A settlement agreement between the United States and a lessee resulting from administrative or judicial litigation;
(3) A written agreement between the lessee and the MMS Director establishing a method to determine the value of production from any lease that MMS expects at least would approximate the value established under this subpart; or
(4) An express provision of an oil and gas lease subject to this subpart; then the statute, settlement agreement, written agreement, or lease provision will govern to the extent of the inconsistency.
(c) All royalty payments made to MMS are subject to audit and adjustment.
(d) The regulations in this subpart are intended to ensure that the administration of oil and gas leases is discharged in accordance with the requirements of the governing mineral leasing laws and lease terms.
[61 FR 5464, Feb. 12, 1996, as amended at 70 FR 11877, Mar. 10, 2005]
§ 206.151
Definitions.
For purposes of this subpart:
Affiliate means a person who controls, is controlled by, or is under common control with another person. For purposes of this subpart:
(1) Ownership or common ownership of more than 50 percent of the voting securities, or instruments of ownership, or other forms of ownership, of another person constitutes control. Ownership of less than 10 percent constitutes a presumption of noncontrol that MMS may rebut.
(2) If there is ownership or common ownership of 10 through 50 percent of the voting securities or instruments of ownership, or other forms of ownership, of another person, MMS will consider the following factors in determining whether there is control under the circumstances of a particular case:
(i) The extent to which there are common officers or directors;
(ii) With respect to the voting securities, or instruments of ownership, or other forms of ownership: The percentage of ownership or common ownership, the relative percentage of ownership or common ownership compared to the percentage(s) of ownership by other persons, whether a person is the greatest single owner, or whether there is an opposing voting bloc of greater ownership;
(iii) Operation of a lease, plant, pipeline, or other facility;
(iv) The extent of participation by other owners in operations and day-to-day management of a lease, plant, pipeline, or other facility; and
(v) Other evidence of power to exercise control over or common control with another person.
(3) Regardless of any percentage of ownership or common ownership, relatives, either by blood or marriage, are affiliates.
Allowance means a deduction in determining value for royalty purposes. Processing allowance means an allowance for the reasonable, actual costs of processing gas determined under this subpart. Transportation allowance means an allowance for the reasonable, actual costs of moving unprocessed gas, residue gas, or gas plant products to a point of sale or delivery off the lease, unit area, or communitized area, or away from a processing plant. The transportation allowance does not include gathering costs.
Area means a geographic region at least as large as the defined limits of an oil and/or gas field, in which oil and/or gas lease products have similar quality, economic, and legal characteristics.
Arm's-length contract means a contract or agreement between independent persons who are not affiliates and who have opposing economic interests regarding that contract. To be considered arm's length for any production month, a contract must satisfy this definition for that month, as well as when the contract was executed.
Audit means a review, conducted in accordance with generally accepted accounting and auditing standards, of royalty payment compliance activities of lessees or other interest holders who pay royalties, rents, or bonuses on Federal leases.
BLM means the Bureau of Land Management of the Department of the Interior.
Compression means the process of raising the pressure of gas.
Condensate means liquid hydrocarbons (normally exceeding 40 degrees of API gravity) recovered at the surface without resorting to processing. Condensate is the mixture of liquid hydrocarbons that results from condensation of petroleum hydrocarbons existing initially in a gaseous phase in an underground reservoir.
Contract means any oral or written agreement, including amendments or revisions thereto, between two or more persons and enforceable by law that with due consideration creates an obligation.
Field means a geographic region situated over one or more subsurface oil and gas reservoirs encompassing at least the outermost boundaries of all oil and gas accumulations known to be within those reservoirs vertically projected to the land surface. Onshore fields are usually given names and their official boundaries are often designated by oil and gas regulatory agencies in the respective States in which the fields are located. Outer Continental Shelf (OCS) fields are named and their boundaries are designated by MMS.
Gas means any fluid, either combustible or noncombustible, hydrocarbon or nonhydrocarbon, which is extracted from a reservoir and which has neither independent shape nor volume, but tends to expand indefinitely. It is a substance that exists in a gaseous or rarefied state under standard temperature and pressure conditions.
Gas plant products means separate marketable elements, compounds, or mixtures, whether in liquid, gaseous, or solid form, resulting from processing gas, excluding residue gas.
Gathering means the movement of lease production to a central accumulation and/or treatment point on the lease, unit or communitized area, or to a central accumulation or treatment point off the lease, unit or communitized area as approved by BLM or MMS OCS operations personnel for onshore and OCS leases, respectively.
Gross proceeds (for royalty payment purposes) means the total monies and other consideration accruing to an oil and gas lessee for the disposition of the gas, residue gas, and gas plant products produced. Gross proceeds includes, but is not limited to, payments to the lessee for certain services such as dehydration, measurement, and/or gathering to the extent that the lessee is obligated to perform them at no cost to the Federal Government. Tax reimbursements are part of the gross proceeds accruing to a lessee even though the Federal royalty interest may be exempt from taxation. Monies and other consideration, including the forms of consideration identified in this paragraph, to which a lessee is contractually or legally entitled but which it does not seek to collect through reasonable efforts are also part of gross proceeds.
Lease means any contract, profit-share arrangement, joint venture, or other agreement issued or approved by the United States under a mineral leasing law that authorizes exploration for, development or extraction of, or removal of lease products—or the land area covered by that authorization, whichever is required by the context.
Lease products means any leased minerals attributable to, originating from, or allocated to Outer Continental Shelf or onshore Federal leases.
Lessee means any person to whom the United States issues a lease, and any person who has been assigned an obligation to make royalty or other payments required by the lease. This includes any person who has an interest in a lease as well as an operator or payor who has no interest in the lease but who has assumed the royalty payment responsibility.
Like-quality lease products means lease products which have similar chemical, physical, and legal characteristics.
Marketable condition means lease products which are sufficiently free from impurities and otherwise in a condition that they will be accepted by a purchaser under a sales contract typical for the field or area.
Marketing affiliate means an affiliate of the lessee whose function is to acquire only the lessee's production and to market that production.
Minimum royalty means that minimum amount of annual royalty that the lessee must pay as specified in the lease or in applicable leasing regulations.
Net-back method (or work-back method) means a method for calculating market value of gas at the lease. Under this method, costs of transportation, processing, or manufacturing are deducted from the proceeds received for the gas, residue gas or gas plant products, and any extracted, processed, or manufactured products, or from the value of the gas, residue gas or gas plant products, and any extracted, processed, or manufactured products, at the first point at which reasonable values for any such products may be determined by a sale pursuant to an arm's-length contract or comparison to other sales of such products, to ascertain value at the lease.
Net output means the quantity of residue gas and each gas plant product that a processing plant produces.
Net profit share (for applicable Federal leases) means the specified share of the net profit from production of oil and gas as provided in the agreement.
Netting means the deduction of an allowance from the sales value by reporting a net sales value, instead of correctly reporting the deduction as a separate entry on Form MMS-2014.
Outer Continental Shelf (OCS) means all submerged lands lying seaward and outside of the area of land beneath navigable waters as defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of which the subsoil and seabed appertain to the United States and are subject to its jurisdiction and control.
Person means any individual, firm, corporation, association, partnership, consortium, or joint venture (when established as a separate entity).
Posted price means the price, net of all adjustments for quality and location, specified in publicly available price bulletins or other price notices available as part of normal business operations for quantities of unprocessed gas, residue gas, or gas plant products in marketable condition.
Processing means any process designed to remove elements or compounds (hydrocarbon and nonhydrocarbon) from gas, including absorption, adsorption, or refrigeration. Field processes which normally take place on or near the lease, such as natural pressure reduction, mechanical separation, heating, cooling, dehydration, and compression, are not considered processing. The changing of pressures and/or temperatures in a reservoir is not considered processing.
Residue gas means that hydrocarbon gas consisting principally of methane resulting from processing gas.
Sales type code means the contract type or general disposition (e.g., arm's-length or non-arm's-length) of production from the lease. The sales type code applies to the sales contract, or other disposition, and not to the arm's-length or non-arm's-length nature of a transportation or processing allowance.
Section 6 lease means an OCS lease subject to section 6 of the Outer Continental Shelf Lands Act, as amended, 43 U.S.C. 1335.
Spot sales agreement means a contract wherein a seller agrees to sell to a buyer a specified amount of unprocessed gas, residue gas, or gas plant products at a specified price over a fixed period, usually of short duration, which does not normally require a cancellation notice to terminate, and which does not contain an obligation, nor imply an intent, to continue in subsequent periods.
Warranty contract means a long-term contract entered into prior to 1970, including any amendments thereto, for the sale of gas wherein the producer agrees to sell a specific amount of gas and the gas delivered in satisfaction of this obligation may come from fields or sources outside of the designated fields.
[53 FR 1272, Jan. 15, 1988, as amended at 53 FR 45084, Nov. 8, 1988; 61 FR 5464, Feb. 12, 1996; 64 FR 43288, Aug. 10, 1999; 70 FR 11878, Mar. 10, 2005; 73 FR 15890, Mar. 26, 2008]
§ 206.152
Valuation standards—unprocessed gas.
(a)(1) This section applies to the valuation of all gas that is not processed and all gas that is processed but is sold or otherwise disposed of by the lessee pursuant to an arm's-length contract prior to processing (including all gas where the lessee's arm's-length contract for the sale of that gas prior to processing provides for the value to be determined on the basis of a percentage of the purchaser's proceeds resulting from processing the gas). This section also applies to processed gas that must be valued prior to processing in accordance with § 206.155 of this part. Where the lessee's contract includes a reservation of the right to process the gas and the lessee exercises that right, § 206.153 of this part shall apply instead of this section.
(2) The value of production, for royalty purposes, of gas subject to this subpart shall be the value of gas determined under this section less applicable allowances.
(b)(1)(i) The value of gas sold under an arm's-length contract is the gross proceeds accruing to the lessee except as provided in paragraphs (b)(1)(ii), (iii), and (iv) of this section. The lessee shall have the burden of demonstrating that its contract is arm's-length. The value which the lessee reports, for royalty purposes, is subject to monitoring, review, and audit. For purposes of this section, gas which is sold or otherwise transferred to the lessee's marketing affiliate and then sold by the marketing affiliate pursuant to an arm's-length contract shall be valued in accordance with this paragraph based upon the sale by the marketing affiliate. Also, where the lessee's arm's-length contract for the sale of gas prior to processing provides for the value to be determined based upon a percentage of the purchaser's proceeds resulting from processing the gas, the value of production, for royalty purposes, shall never be less than a value equivalent to 100 percent of the value of the residue gas attributable to the processing of the lessee's gas.
(ii) In conducting reviews and audits, MMS will examine whether the contract reflects the total consideration actually transferred either directly or indirectly from the buyer to the seller for the gas. If the contract does not reflect the total consideration, then the MMS may require that the gas sold pursuant to that contract be valued in accordance with paragraph (c) of this section. Value may not be less than the gross proceeds accruing to the lessee, including the additional consideration.
(iii) If the MMS determines that the gross proceeds accruing to the lessee pursuant to an arm's-length contract do not reflect the reasonable value of the production because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then MMS shall require that the gas production be valued pursuant to paragraph (c)(2) or (c)(3) of this section, and in accordance with the notification requirements of paragraph (e) of this section. When MMS determines that the value may be unreasonable, MMS will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's value.
(iv) How to value over-delivered volumes under a cash-out program. This paragraph applies to situations where a pipeline purchases gas from a lessee according to a cash-out program under a transportation contract. For all over-delivered volumes, the royalty value is the price the pipeline is required to pay for volumes within the tolerances for over-delivery specified in the transportation contract. Use the same value for volumes that exceed the over-delivery tolerances even if those volumes are subject to a lower price under the transportation contract. However, if MMS determines that the price specified in the transportation contract for over-delivered volumes is unreasonably low, the lessee must value all over-delivered volumes under paragraph (c)(2) or (c)(3) of this section.
(2) Notwithstanding the provisions of paragraph (b)(1) of this section, the value of gas sold pursuant to a warranty contract shall be determined by MMS, and due consideration will be given to all valuation criteria specified in this section. The lessee must request a value determination in accordance with paragraph (g) of this section for gas sold pursuant to a warranty contract; provided, however, that any value determination for a warranty contract in effect on the effective date of these regulations shall remain in effect until modified by MMS.
(3) MMS may require a lessee to certify that its arm's-length contract provisions include all of the consideration to be paid by the buyer, either directly or indirectly, for the gas.
(c) The value of gas subject to this section which is not sold pursuant to an arm's-length contract shall be the reasonable value determined in accordance with the first applicable of the following methods:
(1) The gross proceeds accruing to the lessee pursuant to a sale under its non-arm's-length contract (or other disposition other than by an arm's-length contract), provided that those gross proceeds are equivalent to the gross proceeds derived from, or paid under, comparable arm's-length contracts for purchases, sales, or other dispositions of like-quality gas in the same field (or, if necessary to obtain a reasonable sample, from the same area). In evaluating the comparability of arm's-length contracts for the purposes of these regulations, the following factors shall be considered: price, time of execution, duration, market or markets served, terms, quality of gas, volume, and such other factors as may be appropriate to reflect the value of the gas;
(2) A value determined by consideration of other information relevant in valuing like-quality gas, including gross proceeds under arm's-length contracts for like-quality gas in the same field or nearby fields or areas, posted prices for gas, prices received in arm's-length spot sales of gas, other reliable public sources of price or market information, and other information as to the particular lease operation or the saleability of the gas; or
(3) A net-back method or any other reasonable method to determine value.
(d)(1) Notwithstanding any other provisions of this section, except paragraph (h) of this section, if the maximum price permitted by Federal law at which gas may be sold is less than the value determined pursuant to this section, then MMS shall accept such maximum price as the value. For purposes of this section, price limitations set by any State or local government shall not be considered as a maximum price permitted by Federal law.
(2) The limitation prescribed in paragraph (d)(1) of this section shall not apply to gas sold pursuant to a warranty contract and valued pursuant to paragraph (b)(2) of this section.
(e)(1) Where the value is determined pursuant to paragraph (c) of this section, the lessee shall retain all data relevant to the determination of royalty value. Such data shall be subject to review and audit, and MMS will direct a lessee to use a different value if it determines that the reported value is inconsistent with the requirements of these regulations.
(2) Any Federal lessee will make available upon request to the authorized MMS or State representatives, to the Office of the Inspector General of the Department of the Interior, or other person authorized to receive such information, arm's-length sales and volume data for like-quality production sold, purchased or otherwise obtained by the lessee from the field or area or from nearby fields or areas.
(3) A lessee shall notify MMS if it has determined value pursuant to paragraph (c)(2) or (c)(3) of this section. The notification shall be by letter to the MMS Associate Director for Minerals Revenue Management or his/her designee. The letter shall identify the valuation method to be used and contain a brief description of the procedure to be followed. The notification required by this paragraph is a one-time notification due no later than the end of the month following the month the lessee first reports royalties on a Form MMS-2014 using a valuation method authorized by paragraph (c)(2) or (c)(3) of this section, and each time there is a change in a method under paragraph (c)(2) or (c)(3) of this section.
(f) If MMS determines that a lessee has not properly determined value, the lessee shall pay the difference, if any, between royalty payments made based upon the value it has used and the royalty payments that are due based upon the value established by MMS. The lessee shall also pay interest on that difference computed pursuant to 30 CFR 218.54. If the lessee is entitled to a credit, MMS will provide instructions for the taking of that credit.
(g) The lessee may request a value determination from MMS. In that event, the lessee shall propose to MMS a value determination method, and may use that method in determining value for royalty purposes until MMS issues its decision. The lessee shall submit all available data relevant to its proposal. The MMS shall expeditiously determine the value based upon the lessee's proposal and any additional information MMS deems necessary. In making a value determination MMS may use any of the valuation criteria authorized by this subpart. That determination shall remain effective for the period stated therein. After MMS issues its determination, the lessee shall make the adjustments in accordance with paragraph (f) of this section.
(h) Notwithstanding any other provision of this section, under no circumstances shall the value of production for royalty purposes be less than the gross proceeds accruing to the lessee for lease production, less applicable allowances.
(i) The lessee must place gas in marketable condition and market the gas for the mutual benefit of the lessee and the lessor at no cost to the Federal Government. Where the value established under this section is determined by a lessee's gross proceeds, that value will be increased to the extent that the gross proceeds have been reduced because the purchaser, or any other person, is providing certain services the cost of which ordinarily is the responsibility of the lessee to place the gas in marketable condition or to market the gas.
(j) Value shall be based on the highest price a prudent lessee can receive through legally enforceable claims under its contract. If there is no contract revision or amendment, and the lessee fails to take proper or timely action to receive prices or benefits to which it is entitled, it must pay royalty at a value based upon that obtainable price or benefit. Contract revisions or amendments shall be in writing and signed by all parties to an arm's-length contract. If the lessee makes timely application for a price increase or benefit allowed under its contract but the purchaser refuses, and the lessee takes reasonable measures, which are documented, to force purchaser compliance, the lessee will owe no additional royalties unless or until monies or consideration resulting from the price increase or additional benefits are received. This paragraph shall not be construed to permit a lessee to avoid its royalty payment obligation in situations where a purchaser fails to pay, in whole or in part or timely, for a quantity of gas.
(k) Notwithstanding any provision in these regulations to the contrary, no review, reconciliation, monitoring, or other like process that results in a redetermination by MMS of value under this section shall be considered final or binding as against the Federal Government or its beneficiaries until the audit period is formally closed.
(l) Certain information submitted to MMS to support valuation proposals, including transportation or extraordinary cost allowances, is exempted from disclosure by the Freedom of Information Act, 5 U.S.C. § 552, or other Federal law. Any data specified by law to be privileged, confidential, or otherwise exempt will be maintained in a confidential manner in accordance with applicable law and regulations. All requests for information about determinations made under this subpart are to be submitted in accordance with the Freedom of Information Act regulation of the Department of the Interior, 43 CFR part 2.
[53 FR 1272, Jan. 15, 1988, as amended at 56 FR 46530, Sept. 13, 1991; 61 FR 5464, Feb. 12, 1996; 62 FR 65761, 65762, Dec. 16, 1997]
§ 206.153
Valuation standards—processed gas.
(a)(1) This section applies to the valuation of all gas that is processed by the lessee and any other gas production to which this subpart applies and that is not subject to the valuation provisions of § 206.152 of this part. This section applies where the lessee's contract includes a reservation of the right to process the gas and the lessee exercises that right.
(2) The value of production, for royalty purposes, of gas subject to this section shall be the combined value of the residue gas and all gas plant products determined pursuant to this section, plus the value of any condensate recovered downstream of the point of royalty settlement without resorting to processing determined pursuant to § 206.102 of this part, less applicable transportation allowances and processing allowances determined pursuant to this subpart.
(b)(1)(i) The value of residue gas or any gas plant product sold under an arm's-length contract is the gross proceeds accruing to the lessee, except as provided in paragraphs (b)(1)(ii), (iii), and (iv) of this section. The lessee shall have the burden of demonstrating that its contract is arm's-length. The value that the lessee reports for royalty purposes is subject to monitoring, review, and audit. For purposes of this section, residue gas or any gas plant product which is sold or otherwise transferred to the lessee's marketing affiliate and then sold by the marketing affiliate pursuant to an arm's-length contract shall be valued in accordance with this paragraph based upon the sale by the marketing affiliate.
(ii) In conducting these reviews and audits, MMS will examine whether or not the contract reflects the total consideration actually transferred either directly or indirectly from the buyer to the seller for the residue gas or gas plant product. If the contract does not reflect the total consideration, then the MMS may require that the residue gas or gas plant product sold pursuant to that contract be valued in accordance with paragraph (c) of this section. Value may not be less than the gross proceeds accruing to the lessee, including the additional consideration.
(iii) If the MMS determines that the gross proceeds accruing to the lessee pursuant to an arm's-length contract do not reflect the reasonable value of the residue gas or gas plant product because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then MMS shall require that the residue gas or gas plant product be valued pursuant to paragraph (c)(2) or (c)(3) of this section, and in accordance with the notification requirements of paragraph (e) of this section. When MMS determines that the value may be unreasonable, MMS will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's value.
(iv) How to value over-delivered volumes under a cash-out program. This paragraph applies to situations where a pipeline purchases gas from a lessee according to a cash-out program under a transportation contract. For all over-delivered volumes, the royalty value is the price the pipeline is required to pay for volumes within the tolerances for over-delivery specified in the transportation contract. Use the same value for volumes that exceed the over-delivery tolerances even if those volumes are subject to a lower price under the transportation contract. However, if MMS determines that the price specified in the transportation contract for over-delivered volumes is unreasonably low, the lessee must value all over-delivered volumes under paragraph (c)(2) or (c)(3) of this section.
(2) Notwithstanding the provisions of paragraph (b)(1) of this section, the value of residue gas sold pursuant to a warranty contract shall be determined by MMS, and due consideration will be given to all valuation criteria specified in this section. The lessee must request a value determination in accordance with paragraph (g) of this section for gas sold pursuant to a warranty contract; provided, however, that any value determination for a warranty contract in effect on the effective date of these regulations shall remain in effect until modified by MMS.
(3) MMS may require a lessee to certify that its arm's-length contract provisions include all of the consideration to be paid by the buyer, either directly or indirectly, for the residue gas or gas plant product.
(c) The value of residue gas or any gas plant product which is not sold pursuant to an arm's-length contract shall be the reasonable value determined in accordance with the first applicable of the following methods:
(1) The gross proceeds accruing to the lessee pursuant to a sale under its non-arm's-length contract (or other disposition other than by an arm's-length contract), provided that those gross proceeds are equivalent to the gross proceeds derived from, or paid under, comparable arm's-length contracts for purchases, sales, or other dispositions of like quality residue gas or gas plant products from the same processing plant (or, if necessary to obtain a reasonable sample, from nearby plants). In evaluating the comparability of arm's-length contracts for the purposes of these regulations, the following factors shall be considered: price, time of execution, duration, market or markets served, terms, quality of residue gas or gas plant products, volume, and such other factors as may be appropriate to reflect the value of the residue gas or gas plant products;
(2) A value determined by consideration of other information relevant in valuing like-quality residue gas or gas plant products, including gross proceeds under arm's-length contracts for like-quality residue gas or gas plant products from the same gas plant or other nearby processing plants, posted prices for residue gas or gas plant products, prices received in spot sales of residue gas or gas plant products, other reliable public sources of price or market information, and other information as to the particular lease operation or the saleability of such residue gas or gas plant products; or
(3) A net-back method or any other reasonable method to determine value.
(d)(1) Notwithstanding any other provisions of this section, except paragraph (h) of this section, if the maximum price permitted by Federal law at which any residue gas or gas plant products may be sold is less than the value determined pursuant to this section, then MMS shall accept such maximum price as the value. For the purposes of this section, price limitations set by any State or local government shall not be considered as a maximum price permitted by Federal law.
(2) The limitation prescribed by paragraph (d)(1) of this section shall not apply to residue gas sold pursuant to a warranty contract and valued pursuant to paragraph (b)(2) of this section.
(e)(1) Where the value is determined pursuant to paragraph (c) of this section, the lessee shall retain all data relevant to the determination of royalty value. Such data shall be subject to review and audit, and MMS will direct a lessee to use a different value if it determines upon review or audit that the reported value is inconsistent with the requirements of these regulations.
(2) Any Federal lessee will make available upon request to the authorized MMS or State representatives, to the Office of the Inspector General of the Department of the Interior, or other persons authorized to receive such information, arm's-length sales and volume data for like-quality residue gas and gas plant products sold, purchased or otherwise obtained by the lessee from the same processing plant or from nearby processing plants.
(3) A lessee shall notify MMS if it has determined any value pursuant to paragraph (c)(2) or (c)(3) of this section. The notification shall be by letter to the MMS Associate Director for Minerals Revenue Management or his/her designee. The letter shall identify the valuation method to be used and contain a brief description of the procedure to be followed. The notification required by this paragraph is a one-time notification due no later than the end of the month following the month the lessee first reports royalties on a Form MMS-2014 using a valuation method authorized by paragraph (c)(2) or (c)(3) of this section, and each time there is a change in a method under paragraph (c)(2) or (c)(3) of this section.
(f) If MMS determines that a lessee has not properly determined value, the lessee shall pay the difference, if any, between royalty payments made based upon the value it has used and the royalty payments that are due based upon the value established by MMS. The lessee shall also pay interest computed on that difference pursuant to 30 CFR 218.54. If the lessee is entitled to a credit, MMS will provide instructions for the taking of that credit.
(g) The lessee may request a value determination from MMS. In that event, the lessee shall propose to MMS a value determination method, and may use that method in determining value for royalty purposes until MMS issues its decision. The lessee shall submit all available data relevant to its proposal. The MMS shall expeditiously determine the value based upon the lessee's proposal and any additional information MMS deems necessary. In making a value determination, MMS may use any of the valuation criteria authorized by this subpart. That determination shall remain effective for the period stated therein. After MMS issues its determination, the lessee shall make the adjustments in accordance with paragraph (f) of this section.
(h) Notwithstanding any other provision of this section, under no circumstances shall the value of production for royalty purposes be less than the gross proceeds accruing to the lessee for residue gas and/or any gas plant products, less applicable transportation allowances and processing allowances determined pursuant to this subpart.
(i) The lessee must place residue gas and gas plant products in marketable condition and market the residue gas and gas plant products for the mutual benefit of the lessee and the lessor at no cost to the Federal Government. Where the value established under this section is determined by a lessee's gross proceeds, that value will be increased to the extent that the gross proceeds have been reduced because the purchaser, or any other person, is providing certain services the cost of which ordinarily is the responsibility of the lessee to place the residue gas or gas plant products in marketable condition or to market the residue gas and gas plant products.
(j) Value shall be based on the highest price a prudent lessee can receive through legally enforceable claims under its contract. Absent contract revision or amendment, if the lessee fails to take proper or timely action to receive prices or benefits to which it is entitled it must pay royalty at a value based upon that obtainable price or benefit. Contract revisions or amendments shall be in writing and signed by all parties to an arm's-length contract. If the lessee makes timely application for a price increase or benefit allowed under its contract but the purchaser refuses, and the lessee takes reasonable measures, which are documented, to force purchaser compliance, the lessee will owe no additional royalties unless or until monies or consideration resulting from the price increase or additional benefits are received. This paragraph shall not be construed to permit a lessee to avoid its royalty payment obligation in situations where a purchaser fails to pay, in whole or in part, or timely, for a quantity of residue gas or gas plant product.
(k) Notwithstanding any provision in these regulations to the contrary, no review, reconciliation, monitoring, or other like process that results in a redetermination by MMS of value under this section shall be considered final or binding against the Federal Government or its beneficiaries until the audit period is formally closed.
(l) Certain information submitted to MMS to support valuation proposals, including transportation allowances, processing allowances or extraordinary cost allowances, is exempted from disclosure by the Freedom of Information Act, 5 U.S.C. 552, or other Federal law. Any data specified by law to be privileged, confidential, or otherwise exempt, will be maintained in a confidential manner in accordance with applicable law and regulations. All requests for information about determinations made under this part are to be submitted in accordance with the Freedom of Information Act regulation of the Department of the Interior, 43 CFR part 2.
[53 FR 1272, Jan. 15, 1988, as amended at 56 FR 46530, Sept. 13, 1991; 61 FR 5465, Feb. 12, 1996; 62 FR 65762, Dec. 16, 1997]
§ 206.154
Determination of quantities and qualities for computing royalties.
(a)(1) Royalties shall be computed on the basis of the quantity and quality of unprocessed gas at the point of royalty settlement approved by BLM or MMS for onshore and OCS leases, respectively.
(2) If the value of gas determined pursuant to § 206.152 of this subpart is based upon a quantity and/or quality that is different from the quantity and/or quality at the point of royalty settlement, as approved by BLM or MMS, that value shall be adjusted for the differences in quantity and/or quality.
(b)(1) For residue gas and gas plant products, the quantity basis for computing royalties due is the monthly net output of the plant even though residue gas and/or gas plant products may be in temporary storage.
(2) If the value of residue gas and/or gas plant products determined pursuant to § 206.153 of this subpart is based upon a quantity and/or quality of residue gas and/or gas plant products that is different from that which is attributable to a lease, determined in accordance with paragraph (c) of this section, that value shall be adjusted for the differences in quantity and/or quality.
(c) The quantity of the residue gas and gas plant products attributable to a lease shall be determined according to the following procedure:
(1) When the net output of the processing plant is derived from gas obtained from only one lease, the quantity of the residue gas and gas plant products on which computations of royalty are based is the net output of the plant.
(2) When the net output of a processing plant is derived from gas obtained from more than one lease producing gas of uniform content, the quantity of the residue gas and gas plant products allocable to each lease shall be in the same proportions as the ratios obtained by dividing the amount of gas delivered to the plant from each lease by the total amount of gas delivered from all leases.
(3) When the net output of a processing plant is derived from gas obtained from more than one lease producing gas of nonuniform content, the quantity of the residue gas allocable to each lease will be determined by multiplying the amount of gas delivered to the plant from the lease by the residue gas content of the gas, and dividing the arithmetical product thus obtained by the sum of the similar arithmetical products separately obtained for all leases from which gas is delivered to the plant, and then multiplying the net output of the residue gas by the arithmetic quotient obtained. The net output of gas plant products allocable to each lease will be determined by multiplying the amount of gas delivered to the plant from the lease by the gas plant product content of the gas, and dividing the arithmetical product thus obtained by the sum of the similar arithmetical products separately obtained for all leases from which gas is delivered to the plant, and then multiplying the net output of each gas plant product by the arithmetic quotient obtained.
(4) A lessee may request MMS approval of other methods for determining the quantity of residue gas and gas plant products allocable to each lease. If approved, such method will be applicable to all gas production from Federal leases that is processed in the same plant.
(d)(1) No deductions may be made from the royalty volume or royalty value for actual or theoretical losses. Any actual loss of unprocessed gas that may be sustained prior to the royalty settlement metering or measurement point will not be subject to royalty provided that such loss is determined to have been unavoidable by BLM or MMS, as appropriate.
(2) Except as provided in paragraph (d)(1) of this section and 30 CFR 202.151(c), royalties are due on 100 percent of the volume determined in accordance with paragraphs (a) through (c) of this section. There can be no reduction in that determined volume for actual losses after the quantity basis has been determined or for theoretical losses that are claimed to have taken place. Royalties are due on 100 percent of the value of the unprocessed gas, residue gas, and/or gas plant products as provided in this subpart, less applicable allowances. There can be no deduction from the value of the unprocessed gas, residue gas, and/or gas plant products to compensate for actual losses after the quantity basis has been determined, or for theoretical losses that are claimed to have taken place.
[53 FR 1272, Jan. 15, 1988, as amended at 61 FR 5465, Feb. 12, 1996]
§ 206.155
Accounting for comparison.
(a) Except as provided in paragraph (b) of this section, where the lessee (or a person to whom the lessee has transferred gas pursuant to a non-arm's-length contract or without a contract) processes the lessee's gas and after processing the gas the residue gas is not sold pursuant to an arm's-length contract, the value, for royalty purposes, shall be the greater of (1) the combined value, for royalty purposes, of the residue gas and gas plant products resulting from processing the gas determined pursuant to § 206.153 of this subpart, plus the value, for royalty purposes, of any condensate recovered downstream of the point of royalty settlement without resorting to processing determined pursuant to § 206.102 of this subpart; or (2) the value, for royalty purposes, of the gas prior to processing determined in accordance with § 206.152 of this subpart.
(b) The requirement for accounting for comparison contained in the terms of leases will govern as provided in § 206.150(b) of this subpart. When accounting for comparison is required by the lease terms, such accounting for comparison shall be determined in accordance with paragraph (a) of this section.
[53 FR 1272, Jan. 15, 1988, as amended at 61 FR 5465, Feb. 12, 1996]
§ 206.156
Transportation allowances—general.
(a) Where the value of gas has been determined pursuant to § 206.152 or § 206.153 of this subpart at a point (e.g., sales point or point of value determination) off the lease, MMS shall allow a deduction for the reasonable actual costs incurred by the lessee to transport unprocessed gas, residue gas, and gas plant products from a lease to a point off the lease including, if appropriate, transportation from the lease to a gas processing plant off the lease and from the plant to a point away from the plant.
(b) Transportation costs must be allocated among all products produced and transported as provided in § 206.157.
(c)(1) Except as provided in paragraph (c)(3) of this section, for unprocessed gas valued in accordance with § 206.152 of this subpart, the transportation allowance deduction on the basis of a sales type code may not exceed 50 percent of the value of the unprocessed gas determined under § 206.152 of this subpart.
(2) Except as provided in paragraph (c)(3) of this section, for gas production valued in accordance with § 206.153 of this subpart, the transportation allowance deduction on the basis of a sales type code may not exceed 50 percent of the value of the residue gas or gas plant product determined under § 206.153 of this subpart. For purposes of this section, natural gas liquids will be considered one product.
(3) Upon request of a lessee, MMS may approve a transportation allowance deduction in excess of the limitations prescribed by paragraphs (c)(1) and (c)(2) of this section. The lessee must demonstrate that the transportation costs incurred in excess of the limitations prescribed in paragraphs (c)(1) and (c)(2) of this section were reasonable, actual, and necessary. An application for exception (using Form MMS-4393, Request to Exceed Regulatory Allowance Limitation) must contain all relevant and supporting documentation necessary for MMS to make a determination. Under no circumstances may the value for royalty purposes under any sales type code be reduced to zero.
(d) If, after a review or audit, MMS determines that a lessee has improperly determined a transportation allowance authorized by this subpart, then the lessee must pay any additional royalties, plus interest, determined in accordance with 30 CFR 218.54, or will be entitled to a credit, with interest. If the lessee takes a deduction for transportation on Form MMS-2014 by improperly netting the allowance against the sales value of the unprocessed gas, residue gas, and gas plant products instead of reporting the allowance as a separate entry, MMS may assess a civil penalty under 30 CFR part 241.
[53 FR 1272, Jan. 15, 1988, as amended at 61 FR 5465, Feb. 12, 1996; 64 FR 43288, Aug. 10, 1999; 73 FR 15890, Mar. 26, 2008]
§ 206.157
Determination of transportation allowances.
(a) Arm's-length transportation contracts. (1)(i) For transportation costs incurred by a lessee under an arm's-length contract, the transportation allowance shall be the reasonable, actual costs incurred by the lessee for transporting the unprocessed gas, residue gas and/or gas plant products under that contract, except as provided in paragraphs (a)(1)(ii) and (a)(1)(iii) of this section, subject to monitoring, review, audit, and adjustment. The lessee shall have the burden of demonstrating that its contract is arm's-length. MMS' prior approval is not required before a lessee may deduct costs incurred under an arm's-length contract. Such allowances shall be subject to the provisions of paragraph (f) of this section. The lessee must claim a transportation allowance by reporting it as a separate entry on the Form MMS-2014.
(ii) In conducting reviews and audits, MMS will examine whether or not the contract reflects more than the consideration actually transferred either directly or indirectly from the lessee to the transporter for the transportation. If the contract reflects more than the total consideration, then the MMS may require that the transportation allowance be determined in accordance with paragraph (b) of this section.
(iii) If the MMS determines that the consideration paid pursuant to an arm's-length transportation contract does not reflect the reasonable value of the transportation because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then MMS shall require that the transportation allowance be determined in accordance with paragraph (b) of this section. When MMS determines that the value of the transportation may be unreasonable, MMS will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's transportation costs.
(2)(i) If an arm's-length transportation contract includes more than one product in a gaseous phase and the transportation costs attributable to each product cannot be determined from the contract, the total transportation costs shall be allocated in a consistent and equitable manner to each of the products transported in the same proportion as the ratio of the volume of each product (excluding waste products which have no value) to the volume of all products in the gaseous phase (excluding waste products which have no value). Except as provided in this paragraph, no allowance may be taken for the costs of transporting lease production which is not royalty bearing without MMS approval.
(ii) Notwithstanding the requirements of paragraph (i), the lessee may propose to MMS a cost allocation method on the basis of the values of the products transported. MMS shall approve the method unless it determines that it is not consistent with the purposes of the regulations in this part.
(3) If an arm's-length transportation contract includes both gaseous and liquid products and the transportation costs attributable to each cannot be determined from the contract, the lessee shall propose an allocation procedure to MMS. The lessee may use the transportation allowance determined in accordance with its proposed allocation procedure until MMS issues its determination on the acceptability of the cost allocation. The lessee shall submit all relevant data to support its proposal. MMS shall then determine the gas transportation allowance based upon the lessee's proposal and any additional information MMS deems necessary. The lessee must submit the allocation proposal within 3 months of claiming the allocated deduction on the Form MMS-2014.
(4) Where the lessee's payments for transportation under an arm's-length contract are not based on a dollar per unit, the lessee shall convert whatever consideration is paid to a dollar value equivalent for the purposes of this section.
(5) Where an arm's-length sales contract price or a posted price includes a provision whereby the listed price is reduced by a transportation factor, MMS will not consider the transportation factor to be a transportation allowance. The transportation factor may be used in determining the lessee's gross proceeds for the sale of the product. The transportation factor may not exceed 50 percent of the base price of the product without MMS approval.
(b) Non-arm's-length or no contract. (1) If a lessee has a non-arm's-length transportation contract or has no contract, including those situations where the lessee performs transportation services for itself, the transportation allowance will be based upon the lessee's reasonable actual costs as provided in this paragraph. All transportation allowances deducted under a non-arm's-length or no contract situation are subject to monitoring, review, audit, and adjustment. The lessee must claim a transportation allowance by reporting it as a separate entry on the Form MMS-2014. When necessary or appropriate, MMS may direct a lessee to modify its estimated or actual transportation allowance deduction.
(2) The transportation allowance for non-arm's-length or no-contract situations shall be based upon the lessee's actual costs for transportation during the reporting period, including operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment in accordance with paragraph (b)(2)(iv)(A) of this section, or a cost equal to the initial depreciable investment in the transportation system multiplied by a rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those costs for depreciable fixed assets (including costs of delivery and installation of capital equipment) which are an integral part of the transportation system.
(i) Allowable operating expenses include: Operations supervision and engineering; operations labor; fuel; utilities; materials; ad valorem property taxes; rent; supplies; and any other directly allocable and attributable operating expense which the lessee can document.
(ii) Allowable maintenance expenses include: Maintenance of the transportation system; maintenance of equipment; maintenance labor; and other directly allocable and attributable maintenance expenses which the lessee can document.
(iii) Overhead directly attributable and allocable to the operation and maintenance of the transportation system is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses.
(iv) A lessee may use either depreciation or a return on depreciable capital investment. After a lessee has elected to use either method for a transportation system, the lessee may not later elect to change to the other alternative without approval of the MMS.
(A) To compute depreciation, the lessee may elect to use either a straight-line depreciation method based on the life of equipment or on the life of the reserves which the transportation system services, or a unit of production method. After an election is made, the lessee may not change methods without MMS approval. A change in ownership of a transportation system shall not alter the depreciation schedule established by the original transporter/lessee for purposes of the allowance calculation. With or without a change in ownership, a transportation system shall be depreciated only once. Equipment shall not be depreciated below a reasonable salvage value.
(B) The MMS shall allow as a cost an amount equal to the allowable initial capital investment in the transportation system multiplied by the rate of return determined pursuant to paragraph (b)(2)(v) of this section. No allowance shall be provided for depreciation. This alternative shall apply only to transportation facilities first placed in service after March 1, 1988.
(v) The rate of return must be 1.3 times the industrial rate associated with Standard & Poor's BBB rating. The BBB rate must be the monthly average rate as published in Standard & Poor's Bond Guide for the first month for which the allowance is applicable. The rate must be redetermined at the beginning of each subsequent calendar year.
(3)(i) The deduction for transportation costs shall be determined on the basis of the lessee's cost of transporting each product through each individual transportation system. Where more than one product in a gaseous phase is transported, the allocation of costs to each of the products transported shall be made in a consistent and equitable manner in the same proportion as the ratio of the volume of each product (excluding waste products which have no value) to the volume of all products in the gaseous phase (excluding waste products which have no value). Except as provided in this paragraph, the lessee may not take an allowance for transporting a product which is not royalty bearing without MMS approval.
(ii) Notwithstanding the requirements of paragraph (b)(3)(i), the lessee may propose to the MMS a cost allocation method on the basis of the values of the products transported. MMS shall approve the method unless it determines that it is not consistent with the purposes of the regulations in this part.
(4) Where both gaseous and liquid products are transported through the same transportation system, the lessee shall propose a cost allocation procedure to MMS. The lessee may use the transportation allowance determined in accordance with its proposed allocation procedure until MMS issues its determination on the acceptability of the cost allocation. The lessee shall submit all relevant data to support its proposal. MMS shall then determine the transportation allowance based upon the lessee's proposal and any additional information MMS deems necessary. The lessee must submit the allocation proposal within 3 months of claiming the allocated deduction on the Form MMS-2014.
(5) You may apply for an exception from the requirement to compute actual costs under paragraphs (b)(1) through (b)(4) of this section.
(i) The MMS will grant the exception if:
(A) The transportation system has a tariff filed with the Federal Energy Regulatory Commission (FERC) or a state regulatory agency, that FERC or the state regulatory agency has permitted to become effective, and
(B) Third parties are paying prices, including discounted prices, under the tariff to transport gas on the system under arm's-length transportation contracts.
(ii) If MMS approves the exception, you must calculate your transportation allowance for each production month based on the lesser of the volume-weighted average of the rates paid by the third parties under arm's-length transportation contracts during that production month or the non-arm's-length payment by the lessee to the pipeline.
(iii) If during any production month there are no prices paid under the tariff by third parties to transport gas on the system under arm's-length transportation contracts, you may use the volume-weighted average of the rates paid by third parties under arm's-length transportation contracts in the most recent preceding production month in which the tariff remains in effect and third parties paid such rates, for up to five successive production months. You must use the non-arm's-length payment by the lessee to the pipeline if it is less than the volume-weighted average of the rates paid by third parties under arm's-length contracts.
(c) Reporting requirements—(1) Arm's-length contracts. (i) You must use a separate entry on Form MMS-2014 to notify MMS of a transportation allowance.
(ii) The MMS may require you to submit arm's-length transportation contracts, production agreements, operating agreements, and related documents. Recordkeeping requirements are found at part 207 of this chapter.
(iii) You may not use a transportation allowance that was in effect before March 1, 1988. You must use the provisions of this subpart to determine your transportation allowance.
(2) Non-arm's-length or no contract. (i) You must use a separate entry on Form MMS-2014 to notify MMS of a transportation allowance.
(ii) For new transportation facilities or arrangements, base your initial deduction on estimates of allowable gas transportation costs for the applicable period. Use the most recently available operations data for the transportation system or, if such data are not available, use estimates based on data for similar transportation systems. Paragraph (e) of this section will apply when you amend your report based on your actual costs.
(iii) The MMS may require you to submit all data used to calculate the allowance deduction. Recordkeeping requirements are found at part 207 of this chapter.
(iv) If you are authorized under paragraph (b)(5) of this section to use an exception to the requirement to calculate your actual transportation costs, you must follow the reporting requirements of paragraph (c)(1) of this section.
(v) You may not use a transportation allowance that was in effect before March 1, 1988. You must use the provisions of this subpart to determine your transportation allowance.
(d) Interest and assessments. (1) If a lessee deducts a transportation allowance on its Form MMS-2014 that exceeds 50 percent of the value of the gas transported without obtaining prior approval of MMS under § 206.156, the lessee shall pay interest on the excess allowance amount taken from the date such amount is taken to the date the lessee files an exception request with MMS.
(2) If a lessee erroneously reports a transportation allowance which results in an underpayment of royalties, interest shall be paid on the amount of that underpayment.
(3) Interest required to be paid by this section shall be determined in accordance with 30 CFR 218.54.
(e) Adjustments. (1) If the actual transportation allowance is less than the amount the lessee has taken on Form MMS-2014 for each month during the allowance reporting period, the lessee shall be required to pay additional royalties due plus interest computed under 30 CFR 218.54 from the allowance reporting period when the lessee took the deduction to the date the lessee repays the difference to MMS. If the actual transportation allowance is greater than the amount the lessee has taken on Form MMS-2014 for each month during the allowance reporting period, the lessee shall be entitled to a credit without interest.
(2) For lessees transporting production from onshore Federal leases, the lessee must submit a corrected Form MMS-2014 to reflect actual costs, together with any payment, in accordance with instructions provided by MMS.
(3) For lessees transporting gas production from leases on the OCS, if the lessee's estimated transportation allowance exceeds the allowance based on actual costs, the lessee must submit a corrected Form MMS-2014 to reflect actual costs, together with its payment, in accordance with instructions provided by MMS. If the lessee's estimated transportation allowance is less than the allowance based on actual costs, the refund procedure will be specified by MMS.
(f) Allowable costs in determining transportation allowances. You may include, but are not limited to (subject to the requirements of paragraph (g) of this section), the following costs in determining the arm's-length transportation allowance under paragraph (a) of this section or the non-arm's-length transportation allowance under paragraph (b) of this section. You may not use any cost as a deduction that duplicates all or part of any other cost that you use under this paragraph.
(1) Firm demand charges paid to pipelines. You may deduct firm demand charges or capacity reservation fees paid to a pipeline, including charges or fees for unused firm capacity that you have not sold before you report your allowance. If you receive a payment from any party for release or sale of firm capacity after reporting a transportation allowance that included the cost of that unused firm capacity, or if you receive a payment or credit from the pipeline for penalty refunds, rate case refunds, or other reasons, you must reduce the firm demand charge claimed on the Form MMS-2014 by the amount of that payment. You must modify the Form MMS-2014 by the amount received or credited for the affected reporting period, and pay any resulting royalty and late payment interest due;
(2) Gas supply realignment (GSR) costs. The GSR costs result from a pipeline reforming or terminating supply contracts with producers to implement the restructuring requirements of FERC Orders in 18 CFR part 284;
(3) Commodity charges. The commodity charge allows the pipeline to recover the costs of providing service;
(4) Wheeling costs. Hub operators charge a wheeling cost for transporting gas from one pipeline to either the same or another pipeline through a market center or hub. A hub is a connected manifold of pipelines through which a series of incoming pipelines are interconnected to a series of outgoing pipelines;
(5) Gas Research Institute (GRI) fees. The GRI conducts research, development, and commercialization programs on natural gas related topics for the benefit of the U.S. gas industry and gas customers. GRI fees are allowable provided such fees are mandatory in FERC-approved tariffs;
(6) Annual Charge Adjustment (ACA) fees. FERC charges these fees to pipelines to pay for its operating expenses;
(7) Payments (either volumetric or in value) for actual or theoretical losses. However, theoretical losses are not deductible in non-arm's-length transportation arrangements unless the transportation allowance is based on arm's-length transportation rates charged under a FERC- or state regulatory-approved tariff under paragraph (b)(5) of this section. If you receive volumes or credit for line gain, you must reduce your transportation allowance accordingly and pay any resulting royalties and late payment interest due;
(8) Temporary storage services. This includes short duration storage services offered by market centers or hubs (commonly referred to as “parking” or “banking”), or other temporary storage services provided by pipeline transporters, whether actual or provided as a matter of accounting. Temporary storage is limited to 30 days or less; and
(9) Supplemental costs for compression, dehydration, and treatment of gas. MMS allows these costs only if such services are required for transportation and exceed the services necessary to place production into marketable condition required under §§ 206.152(i) and 206.153(i) of this part.
(10) Costs of surety. You may deduct the costs of securing a letter of credit, or other surety, that the pipeline requires you as a shipper to maintain under an arm's-length transportation contract.
(g) Nonallowable costs in determining transportation allowances. Lessees may not include the following costs in determining the arm's-length transportation allowance under paragraph (a) of this section or the non-arm's-length transportation allowance under paragraph (b) of this section:
(1) Fees or costs incurred for storage. This includes storing production in a storage facility, whether on or off the lease, for more than 30 days;
(2) Aggregator/marketer fees. This includes fees you pay to another person (including your affiliates) to market your gas, including purchasing and reselling the gas, or finding or maintaining a market for the gas production;
(3) Penalties you incur as shipper. These penalties include, but are not limited to:
(i) Over-delivery cash-out penalties. This includes the difference between the price the pipeline pays you for over-delivered volumes outside the tolerances and the price you receive for over-delivered volumes within the tolerances;
(ii) Scheduling penalties. This includes penalties you incur for differences between daily volumes delivered into the pipeline and volumes scheduled or nominated at a receipt or delivery point;
(iii) Imbalance penalties. This includes penalties you incur (generally on a monthly basis) for differences between volumes delivered into the pipeline and volumes scheduled or nominated at a receipt or delivery point; and
(iv) Operational penalties. This includes fees you incur for violation of the pipeline's curtailment or operational orders issued to protect the operational integrity of the pipeline;
(4) Intra-hub transfer fees. These are fees you pay to hub operators for administrative services (e.g., title transfer tracking) necessary to account for the sale of gas within a hub;
(5) Fees paid to brokers. This includes fees paid to parties who arrange marketing or transportation, if such fees are separately identified from aggregator/marketer fees;
(6) Fees paid to scheduling service providers. This includes fees paid to parties who provide scheduling services, if such fees are separately identified from aggregator/marketer fees;
(7) Internal costs. This includes salaries and related costs, rent/space costs, office equipment costs, legal fees, and other costs to schedule, nominate, and account for sale or movement of production; and
(8) Other nonallowable costs. Any cost you incur for services you are required to provide at no cost to the lessor.
(h) Other transportation cost determinations. Use this section when calculating transportation costs to establish value using a netback procedure or any other procedure that requires deduction of transportation costs.
[53 FR 1272, Jan. 15, 1988, as amended at 53 FR 45762, Nov. 14, 1988; 61 FR 5465, Feb. 12, 1996; 62 FR 65762, Dec. 16, 1997; 70 FR 11878, Mar. 10, 2005; 73 FR 15891, Mar. 26, 2008]
§ 206.158
Processing allowances—general.
(a) Where the value of gas is determined pursuant to § 206.153 of this subpart, a deduction shall be allowed for the reasonable actual costs of processing.
(b) Processing costs must be allocated among the gas plant products. A separate processing allowance must be determined for each gas plant product and processing plant relationship. Natural gas liquids (NGL's) shall be considered as one product.
(c)(1) Except as provided in paragraph (d)(2) of this section, the processing allowance shall not be applied against the value of the residue gas. Where there is no residue gas MMS may designate an appropriate gas plant product against which no allowance may be applied.
(2) Except as provided in paragraph (c)(3) of this section, the processing allowance deduction on the basis of an individual product shall not exceed 662/3 percent of the value of each gas plant product determined in accordance with § 206.153 of this subpart (such value to be reduced first for any transportation allowances related to postprocessing transportation authorized by § 206.156 of this subpart).
(3) Upon request of a lessee, MMS may approve a processing allowance in excess of the limitation prescribed by paragraph (c)(2) of this section. The lessee must demonstrate that the processing costs incurred in excess of the limitation prescribed in paragraph (c)(2) of this section were reasonable, actual, and necessary. An application for exception (using Form MMS-4393, Request to Exceed Regulatory Allowance Limitation) shall contain all relevant and supporting documentation for MMS to make a determination. Under no circumstances shall the value for royalty purposes of any gas plant product be reduced to zero.
(d)(1) Except as provided in paragraph (d)(2) of this section, no processing cost deduction shall be allowed for the costs of placing lease products in marketable condition, including dehydration, separation, compression, or storage, even if those functions are performed off the lease or at a processing plant. Where gas is processed for the removal of acid gases, commonly referred to as “sweetening,” no processing cost deduction shall be allowed for such costs unless the acid gases removed are further processed into a gas plant product. In such event, the lessee shall be eligible for a processing allowance as determined in accordance with this subpart. However, MMS will not grant any processing allowance for processing lease production which is not royalty bearing.
(2)(i) If the lessee incurs extraordinary costs for processing gas production from a gas production operation, it may apply to MMS for an allowance for those costs which shall be in addition to any other processing allowance to which the lessee is entitled pursuant to this section. Such an allowance may be granted only if the lessee can demonstrate that the costs are, by reference to standard industry conditions and practice, extraordinary, unusual, or unconventional.
(ii) Prior MMS approval to continue an extraordinary processing cost allowance is not required. However, to retain the authority to deduct the allowance the lessee must report the deduction to MMS in a form and manner prescribed by MMS.
(e) If MMS determines that a lessee has improperly determined a processing allowance authorized by this subpart, then the lessee must pay any additional royalties, plus interest determined under 30 CFR 218.54, or will be entitled to a credit with interest. If the lessee takes a deduction for processing on Form MMS-2014 by improperly netting the allowance against the sales value of the gas plant products instead of reporting the allowance as a separate entry, MMS may assess a civil penalty under 30 CFR part 241.
[53 FR 1272, Jan. 15, 1988, as amended at 61 FR 5466, Feb. 12, 1996; 64 FR 43288, Aug. 10, 1999; 73 FR 15891, Mar. 26, 2008]
§ 206.159
Determination of processing allowances.
(a) Arm's-length processing contracts. (1)(i) For processing costs incurred by a lessee under an arm's-length contract, the processing allowance shall be the reasonable actual costs incurred by the lessee for processing the gas under that contract, except as provided in paragraphs (a)(1)(ii) and (a)(1)(iii) of this section, subject to monitoring, review, audit, and adjustment. The lessee shall have the burden of demonstrating that its contract is arm's-length. MMS' prior approval is not required before a lessee may deduct costs incurred under an arm's-length contract. The lessee must claim a processing allowance by reporting it as a separate entry on the Form MMS-2014.
(ii) In conducting reviews and audits, MMS will examine whether the contract reflects more than the consideration actually transferred either directly or indirectly from the lessee to the processor for the processing. If the contract reflects more than the total consideration, then the MMS may require that the processing allowance be determined in accordance with paragraph (b) of this section.
(iii) If MMS determines that the consideration paid pursuant to an arm's-length processing contract does not reflect the reasonable value of the processing because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and lessor, then MMS shall require that the processing allowance be determined in accordance with paragraph (b) of this section. When MMS determines that the value of the processing may be unreasonable, MMS will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's processing costs.
(2) If an arm's-length processing contract includes more than one gas plant product and the processing costs attributable to each product can be determined from the contract, then the processing costs for each gas plant product shall be determined in accordance with the contract. No allowance may be taken for the costs of processing lease production which is not royalty-bearing.
(3) If an arm's-length processing contract includes more than one gas plant product and the processing costs attributable to each product cannot be determined from the contract, the lessee shall propose an allocation procedure to MMS. The lessee may use its proposed allocation procedure until MMS issues its determination. The lessee shall submit all relevant data to support its proposal. MMS shall then determine the processing allowance based upon the lessee's proposal and any additional information MMS deems necessary. No processing allowance will be granted for the costs of processing lease production which is not royalty bearing. The lessee must submit the allocation proposal within 3 months of claiming the allocated deduction on Form MMS-2014.
(4) Where the lessee's payments for processing under an arm's-length contract are not based on a dollar per unit basis, the lessee shall convert whatever consideration is paid to a dollar value equivalent for the purposes of this section.
(b) Non-arm's-length or no contract. (1) If a lessee has a non-arm's-length processing contract or has no contract, including those situations where the lessee performs processing for itself, the processing allowance will be based upon the lessee's reasonable actual costs as provided in this paragraph. All processing allowances deducted under a non-arm's-length or no-contract situation are subject to monitoring, review, audit, and adjustment. The lessee must claim a processing allowance by reflecting it as a separate entry on the Form MMS-2014. When necessary or appropriate, MMS may direct a lessee to modify its estimated or actual processing allowance.
(2) The processing allowance for non-arm's-length or no-contract situations shall be based upon the lessee's actual costs for processing during the reporting period, including operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment in accordance with paragraph (b)(2)(iv)(A) of this section, or a cost equal to the initial depreciable investment in the processing plant multiplied by a rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those costs for depreciable fixed assets (including costs of delivery and installation of capital equipment) which are an integral part of the processing plant.
(i) Allowable operating expenses include: Operations supervision and engineering; operations labor; fuel; utilities; materials; ad valorem property taxes; rent; supplies; and any other directly allocable and attributable operating expense which the lessee can document.
(ii) Allowable maintenance expenses include: Maintenance of the processing plant; maintenance of equipment; maintenance labor; and other directly allocable and attributable maintenance expenses which the lessee can document.
(iii) Overhead directly attributable and allocable to the operation and maintenance of the processing plant is an allowable expense. State and Federal income taxes and severance taxes, including royalties, are not allowable expenses.
(iv) A lessee may use either depreciation or a return on depreciable capital investment. When a lessee has elected to use either method for a processing plant, the lessee may not later elect to change to the other alternative without approval of the MMS.
(A) To compute depreciation, the lessee may elect to use either a straight-line depreciation method based on the life of equipment or on the life of the reserves which the processing plant services, or a unit-of-production method. After an election is made, the lessee may not change methods without MMS approval. A change in ownership of a processing plant shall not alter the depreciation schedule established by the original processor/lessee for purposes of the allowance calculation. With or without a change in ownership, a processing plant shall be depreciated only once. Equipment shall not be depreciated below a reasonable salvage value.
(B) The MMS shall allow as a cost an amount equal to the allowable initial capital investment in the processing plant multiplied by the rate of return determined pursuant to paragraph (b)(2)(v) of this section. No allowance shall be provided for depreciation. This alternative shall apply only to plants first placed in service after March 1, 1988.
(v) The rate of return must be the industrial rate associated with Standard and Poor's BBB rating. The rate of return must be the monthly average rate as published in Standard and Poor's Bond Guide for the first month for which the allowance is applicable. The rate must be redetermined at the beginning of each subsequent calendar year.
(3) The processing allowance for each gas plant product shall be determined based on the lessee's reasonable and actual cost of processing the gas. Allocation of costs to each gas plant product shall be based upon generally accepted accounting principles. The lessee may not take an allowance for the costs of processing lease production which is not royalty bearing.
(4) A lessee may apply to MMS for an exception from the requirement that it compute actual costs in accordance with paragraphs (b)(1) through (b)(3) of this section. The MMS may grant the exception only if: (i) The lessee has arm's-length contracts for processing other gas production at the same processing plant; and (ii) at least 50 percent of the gas processed annually at the plant is processed pursuant to arm's-length processing contracts; if the MMS grants the exception, the lessee shall use as its processing allowance the volume weighted average prices charged other persons pursuant to arm's-length contracts for processing at the same plant.
(c) Reporting requirements—(1) Arm's-length contracts. (i) The lessee must notify MMS of an allowance based on incurred costs by using a separate entry on the Form MMS-2014.
(ii) The MMS may require that a lessee submit arm's-length processing contracts and related documents. Documents shall be submitted within a reasonable time, as determined by MMS.
(2) Non-arm's-length or no contract. (i) The lessee must notify MMS of an allowance based on the incurred costs by using a separate entry on the Form MMS-2014.
(ii) For new processing plants, the lessee's initial deduction shall include estimates of the allowable gas processing costs for the applicable period. Cost estimates shall be based upon the most recently available operations data for the plant or, if such data are not available, the lessee shall use estimates based upon industry data for similar gas processing plants.
(iii) Upon request by MMS, the lessee shall submit all data used to prepare the allowance deduction. The data shall be provided within a reasonable period of time, as determined by MMS.
(iv) If the lessee is authorized to use the volume weighted average prices charged other persons as its processing allowance in accordance with paragraph (b)(4) of this section, it shall follow the reporting requirements of paragraph (c)(1) of this section.
(d) Interest. (1) If a lessee deducts a processing allowance on its Form MMS-2014 that exceeds 662/3 percent of the value of the gas processed without obtaining prior approval of MMS under § 206.158, the lessee shall pay interest on the excess allowance amount taken from the date such amount is taken to the date the lessee files an exception request with MMS.
(2) If a lessee erroneously reports a processing allowance which results in an underpayment of royalties, interest shall be paid on the amount of that underpayment.
(3) Interest required to be paid by this section shall be determined in accordance with 30 CFR 218.54.
(e) Adjustments. (1) If the actual processing allowance is less than the amount the lessee has taken on Form MMS-2014 for each month during the allowance reporting period, the lessee shall pay additional royalties due plus interest computed under 30 CFR 218.54 from the allowance reporting period when the lessee took the deduction to the date the lessee repays the difference to MMS. If the actual processing allowance is greater than the amount the lessee has taken on Form MMS-2014 for each month during the allowance reporting period, the lessee shall be entitled to a credit with interest.
(2) For lessees processing production from onshore Federal leases, the lessee must submit a corrected Form MMS-2014 to reflect actual costs, together with any payment, in accordance with instructions provided by MMS.
(3) For lessees processing gas production from leases on the OCS, if the lessee's estimated processing allowance exceeds the allowance based on actual costs, the lessee must submit a corrected Form MMS-2014 to reflect actual costs, together with its payment, in accordance with instructions provided by MMS. If the lessee's estimated costs were less than the actual costs, the refund procedure will be specified by MMS.
(f) Other processing cost determinations. The provisions of this section shall apply to determine processing costs when establishing value using a net back valuation procedure or any other procedure that requires deduction of processing costs.
[53 FR 1272, Jan. 15, 1988, as amended at 53 FR 45762, Nov. 14, 1988; 61 FR 5466, Feb. 12, 1996; 64 FR 43288, Aug. 10, 1999; 73 FR 15891, Mar. 26, 2008]
§ 206.160
Operating allowances.
Notwithstanding any other provisions in these regulations, an operating allowance may be used for the purpose of computing payment obligations when specified in the notice of sale and the lease. The allowance amount or formula shall be specified in the notice of sale and in the lease agreement.
[61 FR 3804, Feb. 2, 1996]

Subpart E—Indian Gas

Source:
64 FR 43515, Aug. 10, 1999, unless otherwise noted.
§ 206.170
What does this subpart contain?
This subpart contains royalty valuation provisions applicable to Indian lessees.
(a) This subpart applies to all gas production from Indian (tribal and allotted) oil and gas leases (except leases on the Osage Indian Reservation). The purpose of this subpart is to establish the value of production for royalty purposes consistent with the mineral leasing laws, other applicable laws, and lease terms. This subpart does not apply to Federal leases.
(b) If the specific provisions of any Federal statute, treaty, negotiated agreement, settlement agreement resulting from any administrative or judicial proceeding, or Indian oil and gas lease are inconsistent with any regulation in this subpart, then the Federal statute, treaty, negotiated agreement, settlement agreement, or lease will govern to the extent of that inconsistency.
(c) You may calculate the value of production for royalty purposes under methods other than those the regulations in this title require, but only if you, the tribal lessor, and MMS jointly agree to the valuation methodology. For leases on Indian allotted lands, you and MMS must agree to the valuation methodology.
(d) All royalty payments you make to MMS are subject to monitoring, review, audit, and adjustment.
(e) The regulations in this subpart are intended to ensure that the trust responsibilities of the United States with respect to the administration of Indian oil and gas leases are discharged in accordance with the requirements of the governing mineral leasing laws, treaties, and lease terms.
§ 206.171
What definitions apply to this subpart?
The following definitions apply to this subpart and to subpart J of part 202 of this title:
Accounting for comparison means the same as dual accounting.
Active spot market means a market where one or more MMS-acceptable publications publish bidweek prices (or if bidweek prices are not available, first of the month prices) for at least one index-pricing point in the index zone.
Allowance means a deduction in determining value for royalty purposes. Processing allowance means an allowance for the reasonable, actual costs of processing gas determined under this subpart. Transportation allowance means an allowance for the reasonable, actual cost of transportation determined under this subpart.
Approved Federal Agreement (AFA) means a unit or communitization agreement approved under departmental regulations.
Area means a geographic region at least as large as the defined limits of an oil or gas field, in which oil or gas lease products have similar quality, economic, or legal characteristics. An area may be all lands within the boundaries of an Indian reservation.
Arm's-length contract means a contract or agreement that has been arrived at in the marketplace between independent, nonaffiliated persons with opposing economic interests regarding that contract. For purposes of this subpart, two persons are affiliated if one person controls, is controlled by, or is under common control with another person. The following percentages (based on the instruments of ownership of the voting securities of an entity, or based on other forms of ownership) determine if persons are affiliated:
(1) Ownership in excess of 50 percent constitutes control.
(2) Ownership of 10 through 50 percent creates a presumption of control.
(3) Ownership of less than 10 percent creates a presumption of noncontrol which MMS may rebut if it demonstrates actual or legal control, including the existence of interlocking directorates. Notwithstanding any other provisions of this subpart, contracts between relatives, either by blood or by marriage, are not arm's-length contracts. MMS may require the lessee to certify the percentage of ownership or control of the entity. To be considered arm's-length for any production month, a contract must meet the requirements of this definition for that production month as well as when the contract was executed.
Audit means a review, conducted under generally accepted accounting and auditing standards, of royalty payment compliance activities of lessees or other persons who pay royalties, rents, or bonuses on Indian leases.
BIA means the Bureau of Indian Affairs of the Department of the Interior.
BLM means the Bureau of Land Management of the Department of the Interior.
Compression means raising the pressure of gas.
Condensate means liquid hydrocarbons (normally exceeding 40 degrees of API gravity) recovered at the surface without resorting to processing. Condensate is the mixture of liquid hydrocarbons that results from condensation of petroleum hydrocarbons existing initially in a gaseous phase in an underground reservoir.
Contract means any oral or written agreement, including amendments or revisions thereto, between two or more persons and enforceable by law that with due consideration creates an obligation.
Dedicated means a contractual commitment to deliver gas production (or a specified portion of production) from a lease or well when that production is specified in a sales contract and that production must be sold pursuant to that contract to the extent that production occurs from that lease or well.
Drip condensate means any condensate recovered downstream of the facility measurement point without resorting to processing. Drip condensate includes condensate recovered as a result of its becoming a liquid during the transportation of the gas removed from the lease or recovered at the inlet of a gas processing plant by mechanical means, often referred to as scrubber condensate.
Dual Accounting (or accounting for comparison) refers to the requirement to pay royalty based on a value which is the higher of the value of gas prior to processing less any applicable allowances as compared to the combined value of drip condensate, residue gas, and gas plant products after processing, less applicable allowances.
Entitlement (or entitled share) means the gas production from a lease, or allocable to lease acreage under the terms of an AFA, multiplied by the operating rights owner's percentage of interest ownership in the lease or the acreage.
Facility measurement point (or point of royalty settlement) means the point where the BLM-approved measurement device is located for determining the volume of gas removed from the lease. The facility measurement point may be on the lease or off-lease with BLM approval.
Field means a geographic region situated over one or more subsurface oil and gas reservoirs encompassing at least the outermost boundaries of all oil and gas accumulations known to be within those reservoirs vertically projected to the land surface. Onshore fields are usually given names and their official boundaries are often designated by oil and gas regulatory agencies in the respective States in which the fields are located.
Gas means any fluid, either combustible or noncombustible, hydrocarbon or nonhydrocarbon, which is extracted from a reservoir and which has neither independent shape nor volume, but tends to expand indefinitely. It is a substance that exists in a gaseous or rarefied state under standard temperature and pressure conditions.
Gas plant products means separate marketable elements, compounds, or mixtures, whether in liquid, gaseous, or solid form, resulting from processing gas. However, it does not include residue gas.
Gathering means the movement of lease production to a central accumulation or treatment point on the lease, unit, or communitized area; or a central accumulation or treatment point off the lease, unit, or communitized area as approved by BLM operations personnel.
Gross proceeds (for royalty payment purposes) means the total monies and other consideration accruing to an oil and gas lessee for the disposition of unprocessed gas, residue gas, and gas plant products produced. Gross proceeds includes, but is not limited to, payments to the lessee for certain services such as compression, dehydration, measurement, or field gathering to the extent that the lessee is obligated to perform them at no cost to the Indian lessor, and payments for gas processing rights. Gross proceeds, as applied to gas, also includes but is not limited to reimbursements for severance taxes and other reimbursements. Tax reimbursements are part of the gross proceeds accruing to a lessee even though the Indian royalty interest is exempt from taxation. Monies and other consideration, including the forms of consideration identified in this paragraph, to which a lessee is contractually or legally entitled but which it does not seek to collect through reasonable efforts are also part of gross proceeds.
Index means the calculated composite price ($/MMBtu) of spot-market sales published by a publication that meets MMS-established criteria for acceptability at the index-pricing point.
Index-pricing point (IPP) means any point on a pipeline for which there is an index.
Index zone means a field or an area with an active spot market and published indices applicable to that field or area that are acceptable to MMS under § 206.172(d)(2).
Indian allottee means any Indian for whom land or an interest in land is held in trust by the United States or who holds title subject to Federal restriction against alienation.
Indian tribe means any Indian tribe, band, nation, pueblo, community, rancheria, colony, or other group of Indians for which any land or interest in land is held in trust by the United States or which is subject to Federal restriction against alienation.
Lease means any contract, profit-share arrangement, joint venture, or other agreement issued or approved by the United States under a mineral leasing law that authorizes exploration for, development or extraction of, or removal of lease products—or the land area covered by that authorization, whichever is required by the context. For purposes of this subpart, this definition excludes Federal leases.
Lease products means any leased minerals attributable to, originating from, or allocated to a lease.
Lessee means any person to whom the United States, a tribe, and/or individual Indian landowner issues a lease, and any person who has been assigned an obligation to make royalty or other payments required by the lease. This includes any person who has an interest in a lease (including operating rights owners) as well as an operator or payor who has no interest in the lease but who has assumed the royalty payment responsibility.
Like-quality lease products means lease products which have similar chemical, physical, and legal characteristics.
Marketable condition means a condition in which lease products are sufficiently free from impurities and otherwise so conditioned that a purchaser will accept them under a sales contract typical for the field or area.
MMS means the Minerals Management Service, Department of the Interior. MMS includes, where appropriate, tribal auditors acting under agreements under the Federal Oil and Gas Royalty Management Act of 1982, 30 U.S.C. 1701 et seq. or other applicable agreements.
Minimum royalty means that minimum amount of annual royalty that the lessee must pay as specified in the lease or in applicable leasing regulations.
Natural gas liquids (NGL's) means those gas plant products consisting of ethane, propane, butane, or heavier liquid hydrocarbons.
Net-back method (or work-back method) means a method for calculating market value of gas at the lease under which costs of transportation, processing, and manufacturing are deducted from the proceeds received for, or the value of, the gas, residue gas, or gas plant products, and any extracted, processed, or manufactured products, at the first point at which reasonable values for any such products may be determined by a sale under an arm's-length contract or comparison to other sales of such products.
Net output means the quantity of residue gas and each gas plant product that a processing plant produces.
Net profit share means the specified share of the net profit from production of oil and gas as provided in the agreement.
Operating rights owner (or working interest owner) means any person who owns operating rights in a lease subject to this subpart. A record title owner is the owner of operating rights under a lease except to the extent that the operating rights or a portion thereof have been transferred from record title (see BLM regulations at 43 CFR 3100.0-5(d)).
Person means any individual, firm, corporation, association, partnership, consortium, or joint venture (when established as a separate entity).
Point of royalty measurement means the same as facility measurement point.
Processing means any process designed to remove elements or compounds (hydrocarbon and nonhydrocarbon) from gas, including absorption, adsorption, or refrigeration. Field processes which normally take place on or near the lease, such as natural pressure reduction, mechanical separation, heating, cooling, dehydration, desulphurization (or “sweetening”), and compression, are not considered processing. The changing of pressures and/or temperatures in a reservoir is not considered processing.
Residue gas means that hydrocarbon gas consisting principally of methane resulting from processing gas.
Sales type code means the contract type or general disposition (e.g., arm's-length or non-arm's-length) of production from the lease. The sales type code applies to the sales contract, or other disposition, and not to the arm's-length or non-arm's-length nature of a transportation or processing allowance.
Spot sales agreement means a contract wherein a seller agrees to sell to a buyer a specified amount of unprocessed gas, residue gas, or gas plant products at a specified price over a fixed period, usually of short duration. It also does not normally require a cancellation notice to terminate, and does not contain an obligation, or imply an intent, to continue in subsequent periods.
Takes means when the operating rights owner sells or removes production from, or allocated to, the lease, or when such sale or removal occurs for the benefit of an operating rights owner.
Work-back method means the same as net-back method.
[64 FR 43515, Aug. 10, 1999, as amended at 73 FR 15891, Mar. 26, 2008]
§ 206.172
How do I value gas produced from leases in an index zone?
(a) What leases this section applies to. This section explains how lessees must value, for royalty purposes, gas produced from Indian leases located in an index zone. For other leases, value must be determined under § 206.174.
(1) You must use the valuation provision of this section if your lease is in an index zone and meets one of the following two requirements:
(i) Has a major portion provision;
(ii) Does not have a major portion provision, but provides for the Secretary to determine the value of production.
(2) This section does not apply to carbon dioxide, nitrogen, or other non-hydrocarbon components of the gas stream. However, if they are recovered and sold separately from the gas stream, you must determine the value of these products under § 206.174.
(b) Valuing residue gas and gas before processing. (1) Except as provided in paragraphs (e), (f), and (g) of this section, this paragraph (b) explains how you must value the following four types of gas:
(i) Gas production before processing;
(ii) Gas production that you certify on Form MMS-4410, Certification for Not Performing Accounting for Comparison (Dual Accounting), is not processed before it flows into a pipeline with an index but which may be processed later;
(iii) Residue gas after processing; and
(iv) Gas that is never processed.
(2) The value of gas production that is not sold under an arm's-length dedicated contract is the index-based value determined under paragraph (d) of this section unless the gas was subject to a previous contract which was part of a gas contract settlement. If the previous contract was subject to a gas contract settlement and if the royalty-bearing contract settlement proceeds per MMBtu added to the 80 percent of the safety net prices calculated at § 206.172(e)(4)(i) exceeds the index-based value that applies to the gas under this section (including any adjustments required under § 206.176), then the value of the gas is the higher of the value determined under this section (including any adjustments required under § 206.176) or § 206.174.
(3) The value of gas production that is sold under an arm's-length dedicated contract is the higher of the index-based value under paragraph (d) of this section or the value of that production determined under § 206.174(b).
(c) Valuing gas that is processed before it flows into a pipeline with an index. Except as provided in paragraphs (e), (f), and (g) of this section, this paragraph (c) explains how you must value gas that is processed before it flows into a pipeline with an index. You must value this gas production based on the higher of the following two values:
(1) The value of the gas before processing determined under paragraph (b) of this section.
(2) The value of the gas after processing, which is either the alternative dual accounting value under § 206.173 or the sum of the following three values:
(i) The value of the residue gas determined under paragraph (b)(2) or (3) of this section, as applicable;
(ii) The value of the gas plant products determined under § 206.174, less any applicable processing and/or transportation allowances determined under this subpart; and
(iii) The value of any drip condensate associated with the processed gas determined under subpart B of this part.
(d) Determining the index-based value for gas production. (1) To determine the index-based value per MMBtu for production from a lease in an index zone, you must use the following procedures:
(i) For each MMS-approved publication, calculate the average of the highest reported prices for all index-pricing points in the index zone, except for any prices excluded under paragraph (d)(6) of this section;
(ii) Sum the averages calculated in paragraph (d)(1)(i) of this section and divide by the number of publications; and
(iii) Reduce the number calculated under paragraph (d)(1)(ii) of this section by 10 percent, but not by less than 10 cents per MMBtu or more than 30 cents per MMBtu. The result is the index-based value per MMBtu for production from all leases in that index zone.
(2) MMS will publish in the Federal Register the index zones that are eligible for the index-based valuation method under this paragraph. MMS will monitor the market activity in the index zones and, if necessary, hold a technical conference to add or modify a particular index zone. Any change to the index zones will be published in the Federal Register. MMS will consider the following five factors and conditions in determining eligible index zones:
(i) Areas for which MMS-approved publications establish index prices that accurately reflect the value of production in the field or area where the production occurs;
(ii) Common markets served;
(iii) Common pipeline systems;
(iv) Simplification; and
(v) Easy identification in MMS's systems, such as counties or Indian reservations.
(3) If market conditions change so that an index-based method for determining value is no longer appropriate for an index zone, MMS will hold a technical conference to consider disqualification of an index zone. MMS will publish notice in the Federal Register if an index zone is disqualified. If an index zone is disqualified, then production from leases in that index zone cannot be valued under this paragraph.
(4) MMS periodically will publish in the Federal Register a list of acceptable publications based on certain criteria, including, but not limited to the following five criteria:
(i) Publications buyers and sellers frequently use;
(ii) Publications frequently referenced in purchase or sales contracts;
(iii) Publications that use adequate survey techniques, including the gathering of information from a substantial number of sales;
(iv) Publications that publish the range of reported prices they use to calculate their index; and
(v) Publications independent from DOI, lessors, and lessees.
(5) Any publication may petition MMS to be added to the list of acceptable publications.
(6) MMS may exclude an individual index price for an index zone in an MMS-approved publication if MMS determines that the index price does not accurately reflect the value of production in that index zone. MMS will publish a list of excluded indices in the Federal Register.
(7) MMS will reference which tables in the publications you must use for determining the associated index prices.
(8) The index-based values determined under this paragraph are not subject to deductions for transportation or processing allowances determined under §§ 206.177, 206.178, 206.179, and 206.180.
(e) Determining the minimum value for royalty purposes of gas sold beyond the first index pricing point. (1) Notwithstanding any other provision of this section, the value for royalty purposes of gas production from an Indian lease that is sold beyond the first index pricing point through which it flows cannot be less than the value determined under this paragraph (e).
(2) By June 30 following any calendar year, you must calculate for each month of that calendar year your safety net price per MMBtu using the procedures in paragraph (e)(3) of this section. You must calculate a safety net price for each month and for each index zone where you have an Indian lease for which you report and pay royalties.
(3) Your safety net price (S) for an index zone is the volume-weighted average contract price per delivered MMBtu under your or your affiliate's arm's-length contracts for the disposition of residue gas or unprocessed gas produced from your Indian leases in that index zone as computed under this paragraph (e)(3).
(i) Include in your calculation only sales under those contracts that establish a delivery point beyond the first index pricing point through which the gas flows, and that include any gas produced from or allocable to one or more of your Indian leases in that index zone, even if the contract also includes gas produced from Federal, State, or fee properties. Include in your volume-weighted average calculation those volumes that are allocable to your Indian leases in that index zone.
(ii) Do not reduce the contract price for any transportation costs incurred to deliver the gas to the purchaser.
(iii) For purposes of this paragraph (e), the contract price will not include the following amounts:
(A) Any amounts you receive in compromise or settlement of a predecessor contract for that gas;
(B) Deductions for you or any other person to put gas production into marketable condition or to market the gas; and
(C) Any amounts related to marketable securities associated with the sales contract.
(4) Next, you must determine for each month the safety net differential (SND). You must perform this calculation separately for each index zone.
(i) For each index zone, the safety net differential is equal to: SND = [(0.80 × S) − (1.25 × I)] where (I) is the index-based value determined under 30 CFR 206.172(d).
(ii) If the safety net differential is positive you owe additional royalties.
(5)(i) To calculate the additional royalties you owe, make the following calculation for each of your Indian leases in that index zone that produced gas that was sold beyond the first index-pricing point through which the gas flowed and that was used in the calculation in paragraph (e)(3) of this section:
Lease royalties owed = SND × V × R, where R = the lease royalty rate and V = the volume allocable to the lease which produced gas that was sold beyond the first index pricing point.
(ii) If gas produced from any of your Indian leases is commingled or pooled with gas produced from non-Indian properties, and if any of the combined gas is sold at a delivery point beyond the first index pricing point through which the gas flows, then the volume allocable to each Indian lease for which gas was sold beyond the first index pricing point in the calculation under paragraph (e)(5)(i) of this section is the volume produced from the lease multiplied by the proportion that the total volume of gas sold beyond the first index pricing point bears to the total volume of gas commingled or pooled from all properties.
(iii) Add the numbers calculated for each lease under paragraph (e)(5)(i) of this section. The total is the additional royalty you owe.
(6) You have the following responsibilities to comply with the minimum value for royalty purposes:
(i) You must report the safety net price for each index zone to MMS on Form MMS-4411, Safety Net Report, no later than June 30 following each calendar year;
(ii) You must pay and report on Form MMS-2014 additional royalties due no later than June 30 following each calendar year; and
(iii) MMS may order you to amend your safety net price within one year from the date your Form MMS-4411 is due or is filed, whichever is later. If MMS does not order any amendments within that one-year period, your safety net price calculation is final.
(f) Excluding some or all tribal leases from valuation under this section. (1) An Indian tribe may ask MMS to exclude some or all of its leases from valuation under this section. MMS will consult with BIA regarding the request.
(i) If MMS approves the request for your lease, you must value your production under § 206.174 beginning with production on the first day of the second month following the date MMS publishes notice of its decision in the Federal Register.
(ii) If an Indian tribe requests exclusion from an index zone for less than all of its leases, MMS will approve the request only if the excluded leases may be segregated into one or more groups based on separate fields within the reservation.
(2) An Indian tribe may ask MMS to terminate exclusion of its leases from valuation under this section. MMS will consult with BIA regarding the request.
(i) If MMS approves the request, you must value your production under § 206.172 beginning with production on the first day of the second month following the date MMS publishes notice of its decision in the Federal Register.
(ii) Termination of an exclusion under paragraph (f)(2)(i) of this section cannot take effect earlier than 1 year after the first day of the production month that the exclusion was effective.
(3) The Indian tribe's request to MMS under either paragraph (f)(1) or (2) of this section must be in the form of a tribal resolution.
(g) Excluding Indian allotted leases from valuation under this section. (1)(i) MMS may exclude any Indian allotted leases from valuation under this section. MMS will consult with BIA regarding the exclusion.
(ii) If MMS excludes your lease, you must value your production under § 206.174 beginning with production on the first day of the second month following the date MMS publishes notice of its decision in the Federal Register.
(iii) If MMS excludes any Indian allotted leases under this paragraph (g)(1), it will exclude all Indian allotted leases in the same field.
(2)(i) MMS may terminate the exclusion of any Indian allotted leases from valuation under this section. MMS will consult with BIA regarding the termination.
(ii) If MMS terminates the exclusion, you must value your production under § 206.172 beginning with production on the first day of the second month following the date MMS publishes notice of its decision in the Federal Register.
§ 206.173
How do I calculate the alternative methodology for dual accounting?
(a) Electing a dual accounting method. (1) If you are required to perform the accounting for comparison (dual accounting) under § 206.176, you have two choices. You may elect to perform the dual accounting calculation according to either § 206.176(a) (called actual dual accounting), or paragraph (b) of this section (called the alternative methodology for dual accounting).
(2) You must make a separate election to use the alternative methodology for dual accounting for your Indian leases in each MMS-designated area. Your election for a designated area must apply to all of your Indian leases in that area.
(i) MMS will publish in the Federal Register a list of the lease prefixes that will be associated with each designated area for purposes of this section. The MMS-designated areas are as follows:
(A) Alabama-Coushatta;
(B) Blackfeet Reservation;
(C) Crow Reservation;
(D) Fort Belknap Reservation;
(E) Fort Berthold Reservation;
(F) Fort Peck Reservation;
(G) Jicarilla Apache Reservation;
(H) MMS-designated groups of counties in the State of Oklahoma;
(I) Navajo Reservation;
(J) Northern Cheyenne Reservation;
(K) Rocky Boys Reservation;
(L) Southern Ute Reservation;
(M) Turtle Mountain Reservation;
(N) Ute Mountain Ute Reservation;
(O) Uintah and Ouray Reservation;
(P) Wind River Reservation; and
(Q) Any other area that MMS designates. MMS will publish a new area designation in the Federal Register.
(ii) You may elect to begin using the alternative methodology for dual accounting at the beginning of any month. The first election to use the alternative methodology will be effective from the time of election through the end of the following calendar year. Thereafter, each election to use the alternative methodology must remain in effect for 2 calendar years. You may return to the actual dual accounting method only at the beginning of the next election period or with the written approval of MMS and the tribal lessor for tribal leases, and MMS for Indian allottee leases in the designated area.
(iii) When you elect to use the alternative methodology for a designated area, you must also use the alternative methodology for any new wells commenced and any new leases acquired in the designated area during the term of the election.
(b) Calculating value using the alternative methodology for dual accounting. (1) The alternative methodology adjusts the value of gas before processing determined under either § 206.172 or § 206.174 to provide the value of the gas after processing. You must use the value of the gas after processing for royalty payment purposes. The amount of the increase depends on your relationship with the owner(s) of the plant where the gas is processed. If you have no direct or indirect ownership interest in the processing plant, then the increase is lower, as provided in the table in paragraph (b)(2)(ii) of this section. If you have a direct or indirect ownership interest in the plant where the gas is processed, the increase is higher, as provided in paragraph (b)(2)(ii) of this section.
(2) To calculate the value of the gas after processing using the alternative methodology for dual accounting, you must apply the increase to the value before processing, determined in either § 206.172 or § 206.174, as follows:
(i) Value of gas after processing = (value determined under either § 206.172 or § 206.174, as applicable) × (1 + increment for dual accounting); and
(ii) In this equation, the increment for dual accounting is the number you take from the applicable Btu range, determined under paragraph (b)(3) of this section, in the following table:
BTU range | Increment if Lessee has no ownership interest in plant | Increment if lessee has an ownership interest in plant
1001 to 1050 | .0275 | .0375
1051 to 1100 | .0400 | .0625
1101 to 1150 | .0425 | .0750
1151 to 1200 | .0700 | .1225
1201 to 1250 | .0975 | .1700
1251 to 1300 | .1175 | .2050
1301 to 1350 | .1400 | .2400
1351 to 1400 | .1450 | .2500
1401 to 1450 | .1500 | .2600
1451 to 1500 | .1550 | .2700
1501 to 1550 | .1600 | .2800
1551 to 1600 | .1650 | .2900
1601 to 1650 | .1850 | .3225
1651 to 1700 | .1950 | .3425
1701+ | .2000 | .3550
(3) The applicable Btu for purposes of this section is the volume weighted-average Btu for the lease computed from measurements at the facility measurement point(s) for gas production from the lease.
(4) If any of your gas from the lease is processed during a month, use the following two paragraphs to determine which amounts are subject to dual accounting and which dual accounting method you must use.
(i) Weighted-average Btu content determined under paragraph (b)(3) of this section is greater than 1,000 Btu's per cubic foot (Btu/cf). All gas production from the lease is subject to dual accounting and you must use the alternative method for all that gas production if you elected to use the alternative method under this section.
(ii) Weighted-average Btu content determined under paragraph (b)(3) of this section is less than or equal to 1,000 Btu/cf. Only the volumes of lease production measured at facility measurement points whose quality exceeds 1,000 Btu/cf are subject to dual accounting, and you may use the alternative methodology for these volumes. For gas measured at facility measurement points for these leases where the quality is equal to or less than 1,000 Btu/cf, you are not required to do dual accounting.
§ 206.174
How do I value gas production when an index-based method cannot be used?
(a) Situations in which an index-based method cannot be used. (1) Gas production must be valued under this section in the following situations.
(i) Your lease is not in an index zone (or MMS has excluded your lease from an index zone).
(ii) If your lease is in an index zone and you sell your gas under an arm's-length dedicated contract, then the value of your gas is the higher of the value received under the dedicated contract determined under § 206.174(b) or the value under § 206.172.
(iii) Also use this section to value any other gas production that cannot be valued under § 206.172, as well as gas plant products, and to value components of the gas stream that have no Btu value (for example, carbon dioxide, nitrogen, etc.).
(2) The value for royalty purposes of gas production subject to this subpart is the value of gas determined under this section less applicable allowances determined under this subpart.
(3) You must determine the value of gas production that is processed and is subject to accounting for comparison using the procedure in § 206.176.
(4) This paragraph applies if your lease has a major portion provision. It also applies if your lease does not have a major portion provision but the lease provides for the Secretary to determine value.
(i) The value of production you must initially report and pay is the value determined in accordance with the other paragraphs of this section.
(ii) MMS will determine the major portion value and notify you in the Federal Register of that value. The value of production for royalty purposes for your lease is the higher of either the value determined under this section which you initially used to report and pay royalties, or the major portion value calculated under this paragraph (a)(4). If the major portion value is higher, you must submit an amended Form MMS-2014 to MMS by the due date specified in the written notice from MMS of the major portion value. Late-payment interest under 30 CFR 218.54 on any underpayment will not begin to accrue until the date the amended Form MMS-2014 is due to MMS.
(iii) Except as provided in paragraph (a)(4)(iv) of this section, MMS will calculate the major portion value for each designated area (which are the same designated areas as under § 206.173) using values reported for unprocessed gas and residue gas on Form MMS-2014 for gas produced from leases on that Indian reservation or other designated area. MMS will array the reported prices from highest to lowest price. The major portion value is that price at which 25 percent (by volume) of the gas (starting from the highest) is sold. MMS cannot unilaterally change the major portion value after you are notified in writing of what that value is for your leases.
(iv) MMS may calculate the major portion value using different data than the data described in paragraph (a)(4)(iii) of this section or data to augment the data described in paragraph (a)(4)(iii) of this section. This may include price data reported to the State tax authority or price data from leases MMS has reviewed in the designated area. MMS may use this alternate or the augmented data source beginning with production on the first day of the month following the date MMS publishes notice in the Federal Register that it is calculating the major portion using a method in this paragraph (a)(4)(iv) of this section.
(b) Arm's-length contracts. (1) The value of gas, residue gas, or any gas plant product you sell under an arm's-length contract is the gross proceeds accruing to you or your affiliate, except as provided in paragraphs (b)(1)(ii)-(iv) of this section.
(i) You have the burden of demonstrating that your contract is arm's-length.
(ii) In conducting reviews and audits for gas valued based upon gross proceeds under this paragraph, MMS will examine whether or not your contract reflects the total consideration actually transferred either directly or indirectly from the buyer to you or your affiliate for the gas, residue gas, or gas plant product. If the contract does not reflect the total consideration, then MMS may require that the gas, residue gas, or gas plant product sold under that contract be valued in accordance with paragraph (c) of this section. Value may not be less than the gross proceeds accruing to you or your affiliate, including the additional consideration.
(iii) If MMS determines for gas valued under this paragraph that the gross proceeds accruing to you or your affiliate under an arm's-length contract do not reflect the value of the gas, residue gas, or gas plant products because of misconduct by or between the contracting parties, or because you otherwise have breached your duty to the lessor to market the production for the mutual benefit of you and the lessor, then MMS will require that the gas, residue gas, or gas plant product be valued under paragraphs (c)(2) or (3) of this section. In these circumstances, MMS will notify you and give you an opportunity to provide written information justifying your value.
(iv) This paragraph applies to situations where a pipeline purchases gas from a lessee according to a cash-out program under a transportation contract. For all over-delivered volumes, the royalty value is the price the pipeline is required to pay for volumes within the tolerances for over-delivery specified in the transportation contract. Use the same value for volumes that exceed the over-delivery tolerances even if those volumes are subject to a lower price specified in the transportation contract. However, if MMS determines that the price specified in the transportation contract for over-delivered volumes is unreasonably low, the lessees must value all over-delivered volumes under paragraph (c)(2) or (3) of this section.
(2) MMS may require you to certify that your arm's-length contract provisions include all of the consideration the buyer pays, either directly or indirectly, for the gas, residue gas, or gas plant product.
(c) Non-arm's-length contracts. If your gas, residue gas, or any gas plant product is not sold under an arm's-length contract, then you must value the production using the first applicable method of the following three methods:
(1) The gross proceeds accruing to you under your non-arm's-length contract sale (or other disposition other than by an arm's-length contract), provided that those gross proceeds are equivalent to the gross proceeds derived from, or paid under, comparable arm's-length contracts for purchases, sales, or other dispositions of like-quality gas in the same field (or, if necessary to obtain a reasonable sample, from the same area). For residue gas or gas plant products, the comparable arm's-length contracts must be for gas from the same processing plant (or, if necessary to obtain a reasonable sample, from nearby plants). In evaluating the comparability of arm's-length contracts for the purposes of these regulations, the following factors will be considered: price, time of execution, duration, market or markets served, terms, quality of gas, residue gas, or gas plant products, volume, and such other factors as may be appropriate to reflect the value of the gas, residue gas, or gas plant products.
(2) A value determined by consideration of other information relevant in valuing like-quality gas, residue gas, or gas plant products, including gross proceeds under arm's-length contracts for like-quality gas in the same field or nearby fields or areas, or for residue gas or gas plant products from the same gas plant or other nearby processing plants. Other factors to consider include prices received in spot sales of gas, residue gas or gas plant products, other reliable public sources of price or market information, and other information as to the particular lease operation or the salability of such gas, residue gas, or gas plant products.
(3) A net-back method or any other reasonable method to determine value.
(d) Supporting data. If you determine the value of production under paragraph (c) of this section, you must retain all data relevant to the determination of royalty value.
(1) Such data will be subject to review and audit, and MMS will direct you to use a different value if we determine upon review or audit that the value you reported is inconsistent with the requirements of these regulations.
(2) You must make all such data available upon request to the authorized MMS or Indian representatives, to the Office of the Inspector General of the Department, or other authorized persons. This includes your arm's-length sales and volume data for like-quality gas, residue gas, and gas plant products that are sold, purchased, or otherwise obtained from the same processing plant or from nearby processing plants, or from the same or nearby field or area.
(e) Improper values. If MMS determines that you have not properly determined value, you must pay the difference, if any, between royalty payments made based upon the value you used and the royalty payments that are due based upon the value MMS established. You also must pay interest computed on that difference under 30 CFR 218.54. If you are entitled to a credit, MMS will provide instructions on how to take that credit.
(f) Value guidance. You may ask MMS for guidance in determining value. You may propose a valuation method to MMS. Submit all available data related to your proposal and any additional information MMS deems necessary. MMS will promptly review your proposal and provide you with a non-binding determination of the guidance you request.
(g) Minimum value of production. (1) For gas, residue gas, and gas plant products valued under this section, under no circumstances may the value of production for royalty purposes be less than the gross proceeds accruing to the lessee (including its affiliates) for gas, residue gas and/or any gas plant products, less applicable transportation allowances and processing allowances determined under this subpart.
(2) For gas plant products valued under this section and not valued under § 206.173, the alternative methodology for dual accounting, the minimum value of production for each gas plant product is as follows:
(i) Leases in certain States and areas have specific minimum values.
(A) For production from leases in Colorado in the San Juan Basin, New Mexico, and Texas, the monthly average minimum price reported in commercial price bulletins for the gas plant product at Mont Belvieu, Texas, minus 8.0 cents per gallon.
(B) For production in Arizona, in Colorado outside the San Juan Basin, Minnesota, Montana, North Dakota, Oklahoma, South Dakota, Utah, and Wyoming, the monthly average minimum price reported in commercial price bulletins for the gas plant product at Conway, Kansas, minus 7.0 cents per gallon;
(ii) You may use any commercial price bulletin, but you must use the same bulletin for all of the calendar year. If the commercial price bulletin you are using stops publication, you may use a different commercial price bulletin for the remaining part of the calendar year; and (iii) If you use a commercial price bulletin that is published monthly, the monthly average minimum price is the bulletin's minimum price. If you use a commercial price bulletin that is published weekly, the monthly average minimum price is the arithmetic average of the bulletin's weekly minimum prices. If you use a commercial price bulletin that is published daily, the monthly average minimum price is the arithmetic average of the bulletin's minimum prices for each Wednesday in the month.
(h) Marketable condition/Marketing. You are required to place gas, residue gas, and gas plant products in marketable condition and market the gas for the mutual benefit of the lessee and the lessor at no cost to the Indian lessor. When your gross proceeds establish the value under this section, that value must be increased to the extent that the gross proceeds have been reduced because the purchaser, or any other person, is providing certain services to place the gas, residue gas, or gas plant products in marketable condition or to market the gas, the cost of which ordinarily is your responsibility.
(i) Highest obtainable price or benefit. For gas, residue gas, and gas plant products valued under this section, value must be based on the highest price a prudent lessee can receive through legally enforceable claims under its contract. Absent contract revision or amendment, if you fail to take proper or timely action to receive prices or benefits to which you are entitled, you must pay royalty at a value based upon that obtainable price or benefit. Contract revisions or amendments must be in writing and signed by all parties to an arm's-length contract. If you make timely application for a price increase or benefit allowed under your contract but the purchaser refuses, and you take reasonable measures, which are documented, to force purchaser compliance, you will owe no additional royalties unless or until monies or consideration resulting from the price increase or additional benefits are received. This paragraph is not intended to permit you to avoid your royalty payment obligation in situations where your purchaser fails to pay, in whole or in part, or timely, for a quantity of gas, residue gas, or gas plant product.
(j) Non-binding MMS reviews. Notwithstanding any provision in these regulations to the contrary, no review, reconciliation, monitoring, or other like process that results in an MMS redetermination of value under this section will be considered final or binding against the Federal Government or its beneficiaries until the audit period is formally closed.
(k) Confidential information. Certain information submitted to MMS to support valuation proposals, including transportation allowances and processing allowances, may be exempted from disclosure under the Freedom of Information Act, 5 U.S.C. 552, or other Federal law. Any data specified by law to be privileged, confidential, or otherwise exempt, will be maintained in a confidential manner in accordance with applicable laws and regulations. All requests for information about determinations made under this subpart must be submitted in accordance with the Freedom of Information Act regulation of the Department of the Interior, 43 CFR part 2.
[64 FR 43515, Aug. 10, 1999, as amended at 65 FR 62614, Oct. 19, 2000]
§ 206.175
How do I determine quantities and qualities of production for computing royalties?
(a) For unprocessed gas, you must pay royalties on the quantity and quality at the facility measurement point BLM either allowed or approved.
(b) For residue gas and gas plant products, you must pay royalties on your share of the monthly net output of the plant even though residue gas and/or gas plant products may be in temporary storage.
(c) If you have no ownership interest in the processing plant and you do not operate the plant, you may use the contract volume allocation to determine your share of plant products.
(d) If you have an ownership interest in the plant or if you operate it, use the following procedure to determine the quantity of the residue gas and gas plant products attributable to you for royalty payment purposes:
(1) When the net output of the processing plant is derived from gas obtained from only one lease, the quantity of the residue gas and gas plant products on which you must pay royalty is the net output of the plant.
(2) When the net output of a processing plant is derived from gas obtained from more than one lease producing gas of uniform content, the quantity of the residue gas and gas plant products allocable to each lease must be in the same proportions as the ratios obtained by dividing the amount of gas delivered to the plant from each lease by the total amount of gas delivered from all leases.
(3) When the net output of a processing plant is derived from gas obtained from more than one lease producing gas of non-uniform content, the volumes of residue gas and gas plant products allocable to each lease are based on theoretical volumes of residue gas and gas plant products measured in the lease gas stream. You must calculate the portion of net plant output of residue gas and gas plant products attributable to each lease as follows:
(i) First, compute the theoretical volumes of residue gas and of gas plant products attributable to the lease by multiplying the lease volume of the gas stream by the tested residue gas content (mole percentage) or gas plant product (GPM) content of the gas stream;
(ii) Second, calculate the theoretical volumes of residue gas and of gas plant products delivered from all leases by summing the theoretical volumes of residue gas and of gas plant products delivered from each lease; and
(iii) Third, calculate the theoretical quantities of net plant output of residue gas and of gas plant products attributable to each lease by multiplying the net plant output of residue gas, or gas plant products, by the ratio in which the theoretical volumes of residue gas, or gas plant products, is the numerator and the theoretical volume of residue gas, or gas plant products, delivered from all leases is the denominator.
(4) You may request MMS approval of other methods for determining the quantity of residue gas and gas plant products allocable to each lease. If MMS approves a different method, it will be applicable to all gas production from your Indian leases that is processed in the same plant.
(e) You may not take any deductions from the royalty volume or royalty value for actual or theoretical losses. Any actual loss of unprocessed gas incurred prior to the facility measurement point will not be subject to royalty if BLM determines that the loss was unavoidable.
§ 206.176
How do I perform accounting for comparison?
(a) This section applies if the gas produced from your Indian lease is processed and that Indian lease requires accounting for comparison (also referred to as actual dual accounting). Except as provided in paragraphs (b) and (c) of this section, the actual dual accounting value, for royalty purposes, is the greater of the following two values:
(1) The combined value of the following products:
(i) The residue gas and gas plant products resulting from processing the gas determined under either § 206.172 or § 206.174, less any applicable allowances; and
(ii) Any drip condensate associated with the processed gas recovered downstream of the point of royalty settlement without resorting to processing determined under § 206.52, less applicable allowances.
(2) The value of the gas prior to processing determined under either § 206.172 or § 206.174, including any applicable allowances.
(b) If you are required to account for comparison, you may elect to use the alternative dual accounting methodology provided for in § 206.173 instead of the provisions in paragraph (a) of this section.
(c) Accounting for comparison is not required for gas if no gas from the lease is processed until after the gas flows into a pipeline with an index located in an index zone or into a mainline pipeline not in an index zone. If you do not perform dual accounting, you must certify to MMS that gas flows into such a pipeline before it is processed.
(d) Except as provided in paragraph (e) of this section, if you value any gas production from a lease for a month using the dual accounting provisions of this section or the alternative dual accounting methodology of § 206.173, then the value of that gas is the minimum value for any other gas production from that lease for that month flowing through the same facility measurement point.
(e) If the weighted-average Btu quality for your lease is less than 1,000 Btu's per cubic foot, see § 206.173(b)(4)(ii) to determine if you must perform a dual accounting calculation.

Transportation Allowances
§ 206.177
What general requirements regarding transportation allowances apply to me?
(a) When you value gas under § 206.174 at a point off the lease, unit, or communitized area (for example, sales point or point of value determination), you may deduct from value a transportation allowance to reflect the value, for royalty purposes, at the lease, unit, or communitized area. The allowance is based on the reasonable actual costs you incurred to transport unprocessed gas, residue gas, or gas plant products from a lease to a point off the lease, unit, or communitized area. This would include, if appropriate, transportation from the lease to a gas processing plant off the lease, unit, or communitized area and from the plant to a point away from the plant. You may not deduct any allowance for gathering costs.
(b) You must allocate transportation costs among all products you produce and transport as provided in § 206.178.
(c)(1) Except as provided in paragraphs (c)(2) and (3) of this section, your transportation allowance deduction for each sales type code may not exceed 50 percent of the value of the unprocessed gas, residue gas, or gas plant product. For purposes of this section, natural gas liquids are considered one product.
(2) If you ask MMS, MMS may approve a transportation allowance deduction in excess of the limitations in paragraph (c)(1) of this section. To receive this approval, you must demonstrate that the transportation costs incurred in excess of the limitations in paragraph (c)(1) of this section were reasonable, actual, and necessary. Under no circumstances may an allowance reduce the value for royalty purposes under any sales type code to zero.
(3) Your application for exception (using Form MMS-4393, Request to Exceed Regulatory Allowance Limitation) must contain all relevant and supporting documentation necessary for MMS to make a determination.
(d) If MMS conducts a review or audit and determines that you have improperly determined a transportation allowance authorized by this subpart, then you will be required to pay any additional royalties, plus interest determined in accordance with 30 CFR 218.54. Alternatively, you may be entitled to a credit, but you will not receive any interest on your overpayment.
[64 FR 43515, Aug. 10, 1999, as amended at 73 FR 15891, Mar. 26, 2008]
§ 206.178
How do I determine a transportation allowance?
(a) Determining a transportation allowance under an arm's-length contract. (1) This paragraph explains how to determine your allowance if you have an arm's-length transportation contract.
(i) If you have an arm's-length contract for transportation of your production, the transportation allowance is the reasonable, actual costs you incur for transporting the unprocessed gas, residue gas and/or gas plant products under that contract. Paragraphs (a)(1)(ii) and (iii) of this section provide a limited exception. You have the burden of demonstrating that your contract is arm's-length. Your allowances also are subject to paragraph (e) of this section. You are required to submit to MMS a copy of your arm's-length transportation contract(s) and all subsequent amendments to the contract(s) within 2 months of the date MMS receives your report which claims the allowance on the Form MMS-2014.
(ii) When either MMS or a tribe conducts reviews and audits, they will examine whether or not the contract reflects more than the consideration actually transferred either directly or indirectly from you to the transporter of the transportation. If the contract reflects more than the total consideration, then MMS may require that the transportation allowance be determined under paragraph (b) of this section.
(iii) If MMS determines that the consideration paid under an arm's-length transportation contract does not reflect the value of the transportation because of misconduct by or between the contracting parties, or because you otherwise have breached your duty to the lessor to market the production for the mutual benefit of you and the lessor, then MMS will require that the transportation allowance be determined under paragraph (b) of this section. In these circumstances, MMS will notify you and give you an opportunity to provide written information justifying your transportation costs.
(2) This paragraph explains how to allocate the costs to each product if your arm's-length transportation contract includes more than one product in a gaseous phase and the transportation costs attributable to each product cannot be determined from the contract.
(i) If your arm's-length transportation contract includes more than one product in a gaseous phase and the transportation costs attributable to each product cannot be determined from the contract, the total transportation costs must be allocated in a consistent and equitable manner to each of the products transported. To make this allocation, use the same proportion as the ratio that the volume of each product (excluding waste products which have no value) bears to the volume of all products in the gaseous phase (excluding waste products which have no value). Except as provided in this paragraph, you cannot take an allowance for the costs of transporting lease production that is not royalty bearing without MMS approval, or without lessor approval on tribal leases.
(ii) As an alternative to paragraph (a)(2)(i) of this section, you may propose to MMS a cost allocation method based on the values of the products transported. MMS will approve the method if we determine that it meets one of the two following requirements:
(A) The methodology in paragraph (a)(2)(i) of this section cannot be applied; and
(B) Your proposal is more reasonable than the methodology in paragraph (a)(2)(i) of this section.
(3) This paragraph explains how to allocate costs to each product if your arm's-length transportation contract includes both gaseous and liquid products and the transportation costs attributable to each cannot be determined from the contract.
(i) If your arm's-length transportation contract includes both gaseous and liquid products and the transportation costs attributable to each cannot be determined from the contract, you must propose an allocation procedure to MMS. You may use the transportation allowance determined in accordance with your proposed allocation procedure until MMS decides whether to accept your cost allocation.
(ii) You are required to submit all relevant data to support your allocation proposal. MMS will then determine the gas transportation allowance based upon your proposal and any additional information MMS deems necessary.
(4) If your payments for transportation under an arm's-length contract are not based on a dollar per unit price, you must convert whatever consideration is paid to a dollar value equivalent for the purposes of this section.
(5) Where an arm's-length sales contract price includes a reduction for a transportation factor, MMS will not consider the transportation factor to be a transportation allowance. You may use the transportation factor to determine your gross proceeds for the sale of the product. However, the transportation factor may not exceed 50 percent of the base price of the product without MMS approval.
(b) Determining a transportation allowance under a non-arm's-length or no contract. (1) This paragraph explains how to determine your allowance if you have a non-arm's-length transportation contract or no contract.
(i) When you have a non-arm's-length transportation contract or no contract, including those situations where you perform transportation services for yourself, the transportation allowance is based upon your reasonable, allowable, actual costs for transportation as provided in this paragraph.
(ii) All transportation allowances deducted under a non-arm's-length or no contract situation are subject to monitoring, review, audit, and adjustment. You must submit the actual cost information to support the allowance to MMS on Form MMS-4295, Gas Transportation Allowance Report, within 3 months after the end of the 12-month period to which the allowance applies. However, MMS may approve a longer time period. MMS will monitor the allowance deductions to ensure that deductions are reasonable and allowable. When necessary or appropriate, MMS may require you to modify your actual transportation allowance deduction.
(2) This paragraph explains what actual transportation costs are allowable under a non-arm's-length contract or no contract situation. The transportation allowance for non-arm's-length or no-contract situations is based upon your actual costs for transportation during the reporting period. Allowable costs include operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment (in accordance with paragraph (b)(2)(iv)(A) of this section), or a cost equal to the initial depreciable investment in the transportation system multiplied by a rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those costs for depreciable fixed assets (including costs of delivery and installation of capital equipment) that are an integral part of the transportation system.
(i) Allowable operating expenses include operations supervision and engineering, operations labor, fuel, utilities, materials, ad valorem property taxes, rent, supplies, and any other directly allocable and attributable operating expense that you can document.
(ii) Allowable maintenance expenses include maintenance of the transportation system, maintenance of equipment, maintenance labor, and other directly allocable and attributable maintenance expenses that you can document.
(iii) Overhead directly attributable and allocable to the operation and maintenance of the transportation system is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses.
(iv) You may use either depreciation with a return on undepreciated capital investment or a return on depreciable capital investment. After you have elected to use either method for a transportation system, you may not later elect to change to the other alternative without MMS approval.
(A) To compute depreciation, you may elect to use either a straight-line depreciation method based on the life of equipment or on the life of the reserves that the transportation system services, or a unit of production method. Once you make an election, you may not change methods without MMS approval. A change in ownership of a transportation system will not alter the depreciation schedule that the original transporter/lessee established for purposes of the allowance calculation. With or without a change in ownership, a transportation system may be depreciated only once. Equipment may not be depreciated below a reasonable salvage value. To compute a return on undepreciated capital investment, you will multiply the undepreciated capital investment in the transportation system by the rate of return determined under paragraph (b)(2)(v) of this section.
(B) To compute a return on depreciable capital investment, you will multiply the initial capital investment in the transportation system by the rate of return determined under paragraph (b)(2)(v) of this section. No allowance will be provided for depreciation. This alternative will apply only to transportation facilities first placed in service after March 1, 1988.
(v) The rate of return is the industrial rate associated with Standard and Poor's BBB rating. The rate of return is the monthly average rate as published in Standard and Poor's Bond Guide for the first month of the reporting period for which the allowance is applicable and is effective during the reporting period. The rate must be redetermined at the beginning of each subsequent transportation allowance reporting period that is determined under paragraph (b)(4) of this section.
(3) This paragraph explains how to allocate transportation costs to each product and transportation system.
(i) The deduction for transportation costs must be determined based on your cost of transporting each product through each individual transportation system. If you transport more than one product in a gaseous phase, the allocation of costs to each of the products transported must be made in a consistent and equitable manner. The allocation should be in the same proportion that the volume of each product (excluding waste products that have no value) bears to the volume of all products in the gaseous phase (excluding waste products that have no value). Except as provided in this paragraph, you may not take an allowance for transporting a product that is not royalty bearing without MMS approval.
(ii) As an alternative to the requirements of paragraph (b)(3)(i) of this section, you may propose to MMS a cost allocation method based on the values of the products transported. MMS will approve the method upon determining that it meets one of the two following requirements:
(A) The methodology in paragraph (b)(3)(i) of this section cannot be applied; and
(B) Your proposal is more reasonable than the method in paragraph (b)(3)(i) of this section.
(4) Your transportation allowance under this paragraph (b) must be determined based upon a calendar year or other period if you and MMS agree to an alternative.
(5) If you transport both gaseous and liquid products through the same transportation system, you must propose a cost allocation procedure to MMS. You may use the transportation allowance determined in accordance with your proposed allocation procedure until MMS issues its determination on the acceptability of the cost allocation. You are required to submit all relevant data to support your proposal. MMS will then determine the transportation allowance based upon your proposal and any additional information MMS deems necessary.
(c) Using the alternative transportation calculation when you have a non-arm's-length or no contract. (1) As an alternative to computing your transportation allowance under paragraph (b) of this section, you may use as the transportation allowance 10 percent of your gross proceeds but not to exceed 30 cents per MMBtu.
(2) Your election to use the alternative transportation allowance calculation in paragraph (c)(1) of this section must be made at the beginning of a month and must remain in effect for an entire calendar year. Your first election will remain in effect until the end of the succeeding calendar year, except for elections effective January 1 that will be effective only for that calendar year.
(d) Reporting your transportation allowance. (1) If MMS requests, you must submit all data used to determine your transportation allowance. The data must be provided within a reasonable period of time that MMS will determine.
(2) You must report transportation allowances as a separate entry on Form MMS-2014. MMS may approve a different reporting procedure on allottee leases, and with lessor approval on tribal leases.
(e) Adjusting incorrect allowances. If for any month the transportation allowance you are entitled to is less than the amount you took on Form MMS-2014, you are required to report and pay additional royalties due, plus interest computed under 30 CFR 218.54 from the first day of the first month you deducted the improper transportation allowance until the date you pay the royalties due. If the transportation allowance you are entitled to is greater than the amount you took on Form MMS-2014 for any royalties during the reporting period, you are entitled to a credit. No interest will be paid on the overpayment.
(f) Determining allowable costs for transportation allowances. Lessees may include, but are not limited to, the following costs in determining the arm's-length transportation allowance under paragraph (a) of this section or the non-arm's-length transportation allowance under paragraph (b) of this section:
(1) Firm demand charges paid to pipelines. You must limit the allowable costs for the firm demand charges to the applicable rate per MMBtu multiplied by the actual volumes transported. You may not include any losses incurred for previously purchased but unused firm capacity. You also may not include any gains associated with releasing firm capacity. If you receive a payment or credit from the pipeline for penalty refunds, rate case refunds, or other reasons, you must reduce the firm demand charge claimed on the Form MMS-2014. You must modify the Form MMS-2014 by the amount received or credited for the affected reporting period.
(2) Gas supply realignment (GSR) costs. The GSR costs result from a pipeline reforming or terminating supply contracts with producers to implement the restructuring requirements of FERC orders in 18 CFR part 284.
(3) Commodity charges. The commodity charge allows the pipeline to recover the costs of providing service.
(4) Wheeling costs. Hub operators charge a wheeling cost for transporting gas from one pipeline to either the same or another pipeline through a market center or hub. A hub is a connected manifold of pipelines through which a series of incoming pipelines are interconnected to a series of outgoing pipelines.
(5) Gas Research Institute (GRI) fees. The GRI conducts research, development, and commercialization programs on natural gas related topics for the benefit of the U.S. gas industry and gas customers. GRI fees are allowable provided such fees are mandatory in FERC-approved tariffs.
(6) Annual Charge Adjustment (ACA) fees. FERC charges these fees to pipelines to pay for its operating expenses.
(7) Payments (either volumetric or in value) for actual or theoretical losses. This paragraph does not apply to non-arm's-length transportation arrangements.
(8) Temporary storage services. This includes short duration storage services offered by market centers or hubs (commonly referred to as “parking” or “banking”), or other temporary storage services provided by pipeline transporters, whether actual or provided as a matter of accounting. Temporary storage is limited to 30 days or less.
(9) Supplemental costs for compression, dehydration, and treatment of gas. MMS allows these costs only if such services are required for transportation and exceed the services necessary to place production into marketable condition required under § 206.174(h).
(g) Determining nonallowable costs for transportation allowances. Lessees may not include the following costs in determining the arm's-length transportation allowance under paragraph (a) of this section or the non-arm's-length transportation allowance under paragraph (b) of this section:
(1) Fees or costs incurred for storage. This includes storing production in a storage facility, whether on or off the lease, for more than 30 days.
(2) Aggregater/marketer fees. This includes fees you pay to another person (including your affiliates) to market your gas, including purchasing and reselling the gas, or finding or maintaining a market for the gas production.
(3) Penalties you incur as shipper. These penalties include, but are not limited to the following:
(i) Over-delivery cash-out penalties. This includes the difference between the price the pipeline pays you for over-delivered volumes outside the tolerances and the price you receive for over-delivered volumes within tolerances.
(ii) Scheduling penalties. This includes penalties you incur for differences between daily volumes delivered into the pipeline and volumes scheduled or nominated at a receipt or delivery point.
(iii) Imbalance penalties. This includes penalties you incur (generally on a monthly basis) for differences between volumes delivered into the pipeline and volumes scheduled or nominated at a receipt or delivery point.
(iv) Operational penalties. This includes fees you incur for violation of the pipeline's curtailment or operational orders issued to protect the operational integrity of the pipeline.
(4) Intra-hub transfer fees. These are fees you pay to hub operators for administrative services (e.g., title transfer tracking) necessary to account for the sale of gas within a hub.
(5) Other nonallowable costs. Any cost you incur for services you are required to provide at no cost to the lessor.
(h) Other transportation cost determinations. You must follow the provisions of this section to determine transportation costs when establishing value using either a net-back valuation procedure or any other procedure that allows deduction of actual transportation costs.
[64 FR 43515, Aug. 10, 1999, as amended at 73 FR 15891, Mar. 26, 2008]

Processing Allowances
§ 206.179
What general requirements regarding processing allowances apply to me?
(a) When you value any gas plant product under § 206.174, you may deduct from value the reasonable actual costs of processing.
(b) You must allocate processing costs among the gas plant products. You must determine a separate processing allowance for each gas plant product and processing plant relationship. Natural gas liquids are considered as one product.
(c) The processing allowance deduction based on an individual product may not exceed 66 2/3 percent of the value of each gas plant product determined under § 206.174. Before you calculate the 66 2/3 percent limit, you must first reduce the value for any transportation allowances related to post-processing transportation authorized under § 206.177.
(d) Processing cost deductions will not be allowed for placing lease products in marketable condition. These costs include among others, dehydration, separation, compression upstream of the facility measurement point, or storage, even if those functions are performed off the lease or at a processing plant. Costs for the removal of acid gases, commonly referred to as sweetening, are not allowed unless the acid gases removed are further processed into a gas plant product. In such event, you will be eligible for a processing allowance determined under this subpart. However, MMS will not grant any processing allowance for processing lease production that is not royalty bearing.
(e) You will be allowed a reasonable amount of residue gas royalty free for operation of the processing plant, but no allowance will be made for expenses incidental to marketing, except as provided in 30 CFR part 206. In those situations where a processing plant processes gas from more than one lease, only that proportionate share of your residue gas necessary for the operation of the processing plant will be allowed royalty free.
(f) You do not owe royalty on residue gas, or any gas plant product resulting from processing gas, that is reinjected into a reservoir within the same lease, unit, or approved Federal agreement, until such time as those products are finally produced from the reservoir for sale or other disposition. This paragraph applies only when the reinjection is included in a BLM-approved plan of development or operations.
(g) If MMS determines that you have determined an improper processing allowance authorized by this subpart, then you will be required to pay any additional royalties plus late payment interest determined under 30 CFR 218.54. Alternatively, you may be entitled to a credit, but you will not receive any interest on your overpayment.
§ 206.180
How do I determine an actual processing allowance?
(a) Determining a processing allowance if you have an arms's-length processing contract. (1) This paragraph explains how you determine an allowance under an arm's-length processing contract.
(i) The processing allowance is the reasonable actual costs you incur to process the gas under that contract. Paragraphs (a)(1)(ii) and (iii) of this section provide a limited exception. You have the burden of demonstrating that your contract is arm's-length. You are required to submit to MMS a copy of your arm's-length contract(s) and all subsequent amendments to the contract(s) within 2 months of the date MMS receives your first report that deducts the allowance on the Form MMS-2014.
(ii) When MMS conducts reviews and audits, we will examine whether the contract reflects more than the consideration actually transferred either directly or indirectly from you to the processor for the processing. If the contract reflects more than the total consideration, then MMS may require that the processing allowance be determined under paragraph (b) of this section.
(iii) If MMS determines that the consideration paid under an arm's-length processing contract does not reflect the value of the processing because of misconduct by or between the contracting parties, or because you otherwise have breached your duty to the lessor to market the production for the mutual benefit of you and the lessor, then MMS will require that the processing allowance be determined under paragraph (b) of this section. In these circumstances, MMS will notify you and give you an opportunity to provide written information justifying your processing costs.
(2) If your arm's-length processing contract includes more than one gas plant product and the processing costs attributable to each product can be determined from the contract, then the processing costs for each gas plant product must be determined in accordance with the contract. You may not take an allowance for the costs of processing lease production that is not royalty-bearing.
(3) If your arm's-length processing contract includes more than one gas plant product and the processing costs attributable to each product cannot be determined from the contract, you must propose an allocation procedure to MMS. You may use your proposed allocation procedure until MMS issues its determination. You are required to submit all relevant data to support your proposal. MMS will then determine the processing allowance based upon your proposal and any additional information MMS deems necessary. You may not take a processing allowance for the costs of processing lease production that is not royalty-bearing.
(4) If your payments for processing under an arm's-length contract are not based on a dollar per unit price, you must convert whatever consideration is paid to a dollar value equivalent for the purposes of this section.
(b) Determining a processing allowance if you have a non-arm's-length contract or no contract. (1) This paragraph applies if you have a non-arm's-length processing contract or no contract, including those situations where you perform processing for yourself.
(i) If you have a non-arm's-length contract or no contract, the processing allowance is based upon your reasonable actual costs of processing as provided in paragraph (b)(2) of this section.
(ii) All processing allowances deducted under a non-arm's-length or no-contract situation are subject to monitoring, review, audit, and adjustment. You must submit the actual cost information to support the allowance to MMS on Form MMS-4109, Gas Processing Allowance Summary Report, within 3 months after the end of the 12-month period for which the allowance applies. MMS may approve a longer time period. MMS will monitor the allowance deduction to ensure that deductions are reasonable and allowable. When necessary or appropriate, MMS may require you to modify your processing allowance.
(2) The processing allowance for non-arm's-length or no-contract situations is based upon your actual costs for processing during the reporting period. Allowable costs include operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment (in accordance with paragraph (b)(2)(iv)(A) of this section), or a cost equal to the initial depreciable investment in the processing plant multiplied by a rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those costs for depreciable fixed assets (including costs of delivery and installation of capital equipment) that are an integral part of the processing plant.
(i) Allowable operating expenses include operations supervision and engineering, operations labor, fuel, utilities, materials, ad valorem property taxes, rent, supplies, and any other directly allocable and attributable operating expense that the lessee can document.
(ii) Allowable maintenance expenses include maintenance of the processing plant, maintenance of equipment, maintenance labor, and other directly allocable and attributable maintenance expenses that you can document.
(iii) Overhead directly attributable and allocable to the operation and maintenance of the processing plant is an allowable expense. State and Federal income taxes and severance taxes, including royalties, are not allowable expenses.
(iv) You may use either depreciation with a return on undepreciable capital investment or a return on depreciable capital investment. After you elect to use either method for a processing plant, you may not later elect to change to the other alternative without MMS approval.
(A) To compute depreciation, you may elect to use either a straight-line depreciation method based on the life of equipment or on the life of the reserves that the processing plant services, or a unit-of-production method. Once you make an election, you may not change methods without MMS approval. A change in ownership of a processing plant will not alter the depreciation schedule that the original processor/lessee established for purposes of the allowance calculation. However, for processing plants you or your affiliate purchase that do not have a previously claimed MMS depreciation schedule, you may treat the processing plant as a newly installed facility for depreciation purposes. A processing plant may be depreciated only once, regardless of whether there is a change in ownership. Equipment may not be depreciated below a reasonable salvage value. To compute a return on undepreciated capital investment, you must multiply the undepreciable capital investment in the processing plant by the rate of return determined under paragraph (b)(2)(v) of this section.
(B) To compute a return on depreciable capital investment, you must multiply the initial capital investment in the processing plant by the rate of return determined under paragraph (b)(2)(v) of this section. No allowance will be provided for depreciation. This alternative will apply only to plants first placed in service after March 1, 1988.
(v) The rate of return is the industrial rate associated with Standard and Poor's BBB rating. The rate of return is the monthly average rate as published in Standard and Poor's Bond Guide for the first month for which the allowance is applicable. The rate must be redetermined at the beginning of each subsequent calendar year.
(3) Your processing allowance under this paragraph (b) must be determined based upon a calendar year or other period if you and MMS agree to an alternative.
(4) The processing allowance for each gas plant product must be determined based on your reasonable and actual cost of processing the gas. You must base your allocation of costs to each gas plant product upon generally accepted accounting principles. You may not take an allowance for the costs of processing lease production that is not royalty-bearing.
(c) Reporting your processing allowance. (1) If MMS requests, you must submit all data used to determine your processing allowance. The data must be provided within a reasonable period of time, as MMS determines.
(2) You must report gas processing allowances as a separate entry on the Form MMS-2014. MMS may approve a different reporting procedure for allottee leases, and with lessor approval on tribal leases.
(d) Adjusting incorrect processing allowances. If for any month the gas processing allowance you are entitled to is less than the amount you took on Form MMS-2014, you are required to pay additional royalties, plus interest computed under 30 CFR 218.54 from the first day of the first month you deducted a processing allowance until the date you pay the royalties due. If the processing allowance you are entitled is greater than the amount you took on Form MMS-2014, you are entitled to a credit. However, no interest will be paid on the overpayment.
(e) Other processing cost determinations. You must follow the provisions of this section to determine processing costs when establishing value using either a net-back valuation procedure or any other procedure that requires deduction of actual processing costs.
[64 FR 43515, Aug. 10, 1999, as amended at 73 FR 15891, Mar. 26, 2008]
§ 206.181
How do I establish processing costs for dual accounting purposes when I do not process the gas?
Where accounting for comparison (dual accounting) is required for gas production from a lease but neither you nor someone acting on your behalf processes the gas, and you have elected to perform actual dual accounting under § 206.176, you must use the first applicable of the following methods to establish processing costs for dual accounting purposes:
(a) The average of the costs established in your current arm's-length processing agreements for gas from the lease, provided that some gas has previously been processed under these agreements.
(b) The average of the costs established in your current arm's-length processing agreements for gas from the lease, provided that the agreements are in effect for plants to which the lease is physically connected and under which gas from other leases in the field or area is being or has been processed.
(c) A proposed comparable processing fee submitted to either the tribe and MMS (for tribal leases) or MMS (for allotted leases) with your supporting documentation submitted to MMS. If MMS does not take action on your proposal within 120 days, the proposal will be deemed to be denied and subject to appeal to the MMS Director under 30 CFR part 290.
(d) Processing costs based on the regulations in §§ 206.179 and 206.180.

Subpart F—Federal Coal

Source:
54 FR 1523, Jan. 13, 1989, unless otherwise noted.
§ 206.250
Purpose and scope.
(a) This subpart is applicable to all coal produced from Federal coal leases. The purpose of this subpart is to establish the value of coal produced for royalty purposes, of all coal from Federal leases consistent with the mineral leasing laws, other applicable laws and lease terms.
(b) If the specific provisions of any statute or settlement agreement between the United States and a lessee resulting from administrative or judicial litigation, or any coal lease subject to the requirements of this subpart, are inconsistent with any regulation in this subpart then the statute, lease provision, or settlement shall govern to the extent of that inconsistency.
(c) All royalty payments made to the Minerals Management Service (MMS) are subject to later audit and adjustment.
[54 FR 1523, Jan. 13, 1989, as amended at 61 FR 5479, Feb. 12, 1996; 67 FR 19111, Apr. 18, 2002]
§ 206.251
Definitions.
Ad valorem lease means a lease where the royalty due to the lessor is based upon a percentage of the amount or value of the coal.
Allowance means a deduction used in determining value for royalty purposes. Coal washing allowance means an allowance for the reasonable, actual costs incurred by the lessee for coal washing. Transportation allowance means an allowance for the reasonable, actual costs incurred by the lessee for moving coal to a point of sale or point of delivery remote from both the lease and mine or wash plant.
Area means a geographic region in which coal has similar quality and economic characteristics. Area boundaries are not officially designated and the areas are not necessarily named.
Arm's-length contract means a contract or agreement that has been arrived at in the marketplace between independent, nonaffiliated persons with opposing economic interests regarding that contract. For purposes of this subpart, two persons are affiliated if one person controls, is controlled by, or is under common control with another person. For purposes of this subpart, based on the instruments of ownership of the voting securities of an entity, or based on other forms of ownership:
(a) Ownership in excess of 50 percent constitutes control;
(b) Ownership of 10 through 50 percent creates a presumption of control; and
(c) Ownership of less than 10 percent creates a presumption of noncontrol which MMS may rebut if it demonstrates actual or legal control, including the existence of interlocking directorates.
Notwithstanding any other provisions of this subpart, contracts between relatives, either by blood or by marriage, are not arm's-length contracts. The MMS may require the lessee to certify ownership control. To be considered arm's-length for any production month, a contract must meet the requirements of this definition for that production month as well as when the contract was executed.
Audit means a review, conducted in accordance with generally accepted accounting and auditing standards, of royalty payment compliance activities of lessees or other interest holders who pay royalties, rents, or bonuses on Federal leases.
BLM means the Bureau of Land Management of the Department of the Interior.
Coal means coal of all ranks from lignite through anthracite.
Coal washing means any treatment to remove impurities from coal. Coal washing may include, but is not limited to, operations such as flotation, air, water, or heavy media separation; drying; and related handling (or combination thereof).
Contract means any oral or written agreement, including amendments or revisions thereto, between two or more persons and enforceable by law that with due consideration creates an obligation.
Gross proceeds (for royalty payment purposes) means the total monies and other consideration accruing to a coal lessee for the production and disposition of the coal produced. Gross proceeds includes, but is not limited to, payments to the lessee for certain services such as crushing, sizing, screening, storing, mixing, loading, treatment with substances including chemicals or oils, and other preparation of the coal to the extent that the lessee is obligated to perform them at no cost to the Federal Government. Gross proceeds, as applied to coal, also includes but is not limited to reimbursements for royalties, taxes or fees, and other reimbursements. Tax reimbursements are part of the gross proceeds accruing to a lessee even though the Federal royalty interest may be exempt from taxation. Monies and other consideration, including the forms of consideration identified in this paragraph, to which a lessee is contractually or legally entitled but which it does not seek to collect through reasonable efforts are also part of gross proceeds.
Lease means any contract, profit-share arrangement, joint venture, or other agreement issued or approved by the United States for a Federal coal resource under a mineral leasing law that authorizes exploration for, development or extraction of, or removal of coal—or the land covered by that authorization, whichever is required by the context.
Lessee means any person to whom the United States issues a lease, and any person who has been assigned an obligation to make royalty or other payments required by the lease. This includes any person who has an interest in a lease as well as an operator or payor who has no interest in the lease but who has assumed the royalty payment responsibility.
Like-quality coal means coal that has similar chemical and physical characteristics.
Marketable condition means coal that is sufficiently free from impurities and otherwise in a condition that it will be accepted by a purchaser under a sales contract typical for that area.
Mine means an underground or surface excavation or series of excavations and the surface or underground support facilities that contribute directly or indirectly to mining, production, preparation, and handling of lease products.
Net-back method means a method for calculating market value of coal at the lease or mine. Under this method, costs of transportation, washing, handling, etc., are deducted from the ultimate proceeds received for the coal at the first point at which reasonable values for the coal may be determined by a sale pursuant to an arm's-length contract or by comparison to other sales of coal, to ascertain value at the mine.
Net output means the quantity of washed coal that a washing plant produces.
Netting is the deduction of an allowance from the sales value by reporting a one line net sales value, instead of correctly reporting the deduction as a separate line item on the Form MMS-4430.
Person means by individual, firm, corporation, association, partnership, consortium, or joint venture.
Sales type code means the contract type or general disposition (e.g., arm's-length or non-arm's-length) of production from the lease. The sales type code applies to the sales contract, or other disposition, and not to the arm's-length or non-arm's-length nature of a transportation or washing allowance.
Spot market price means the price received under any sales transaction when planned or actual deliveries span a short period of time, usually not exceeding one year.
[54 FR 1523, Jan. 13, 1989, as amended at 55 FR 35433, Aug. 30, 1990; 61 FR 5479, Feb. 12, 1996; 64 FR 43288, Aug. 10, 1999; 66 FR 45769, Aug. 30, 2001; 73 FR 15891, Mar. 26, 2008]
§ 206.252
Information collection.
The information collection requirements contained in this subpart have been approved by the Office of Management and Budget (OMB) under 44 U.S.C. 3501 et seq. The forms, filing date, and approved OMB control numbers are identified in 30 CFR 210—Forms and Reports.
[73 FR 15891, Mar. 26, 2008]
§ 206.253
Coal subject to royalties—general provisions.
(a) All coal (except coal unavoidably lost as determined by BLM under 43 CFR part 3400) from a Federal lease subject to this part is subject to royalty. This includes coal used, sold, or otherwise disposed of by the lessee on or off the lease.
(b) If a lessee receives compensation for unavoidably lost coal through insurance coverage or other arrangements, royalties at the rate specified in the lease are to be paid on the amount of compensation received for the coal. No royalty is due on insurance compensation received by the lessee for other losses.
(c) If waste piles or slurry ponds are reworked to recover coal, the lessee shall pay royalty at the rate specified in the lease at the time the recovered coal is used, sold, or otherwise finally disposed of. The royalty rate shall be that rate applicable to the production method used to initially mine coal in the waste pile or slurry pond; i.e., underground mining method or surface mining method. Coal in waste pits or slurry ponds initially mined from Federal leases shall be allocated to such leases regardless of whether it is stored on Federal lands. The lessee shall maintain accurate records to determine to which individual Federal lease coal in the waste pit or slurry pond should be allocated. However, nothing in this section requires payment of a royalty on coal for which a royalty has already been paid.
[54 FR 1523, Jan. 13, 1989, as amended at 61 FR 5479, Feb. 12, 1996]
§ 206.254
Quality and quantity measurement standards for reporting and paying royalties.
For all leases subject to this subpart, the quantity of coal on which royalty is due shall be measured in short tons (of 2,000 pounds each) by methods prescribed by the BLM. Coal quantity information will be reported on appropriate forms required under 30 CFR part 210—Forms and Reports.
[54 FR 1523, Jan. 13, 1989, as amended at 57 FR 52720, Nov. 5, 1992; 66 FR 45769, Aug. 30, 2001; 73 FR 15891, Mar. 26, 2008]
§ 206.255
Point of royalty determination.
(a) For all leases subject to this subpart, royalty shall be computed on the basis of the quantity and quality of Federal coal in marketable condition measured at the point of royalty measurement as determined jointly by BLM and MMS.
(b) Coal produced and added to stockpiles or inventory does not require payment of royalty until such coal is later used, sold, or otherwise finally disposed of. MMS may ask BLM to increase the lease bond to protect the lessor's interest when BLM determines that stockpiles or inventory become excessive so as to increase the risk of degradation of the resource.
(c) The lessee shall pay royalty at a rate specified in the lease at the time the coal is used, sold, or otherwise finally disposed of, unless otherwise provided for at § 206.256(d) of this subpart.
[54 FR 1523, Jan. 13, 1989, as amended at 61 FR 5480, Feb. 12, 1996]
§ 206.256
Valuation standards for cents-per-ton leases.
(a) This section is applicable to coal leases on Federal lands which provide for the determination of royalty on a cents-per-ton (or other quantity) basis.
(b) The royalty for coal from leases subject to this section shall be based on the dollar rate per ton prescribed in the lease. That dollar rate shall be applicable to the actual quantity of coal used, sold, or otherwise finally disposed of, including coal which is avoidably lost as determine by BLM pursuant to 43 CFR part 3400.
(c) For leases subject to this section, there shall be no allowances for transportation, removal of impurities, coal washing, or any other processing or preparation of the coal.
(d) When a coal lease is readjusted pursuant to 43 CFR part 3400 and the royalty valuation method changes from a cents-per-ton basis to an ad valorem basis, coal which is produced prior to the effective date of readjustment and sold or used within 30 days of the effective date of readjustment shall be valued pursuant to this section. All coal that is not used, sold, or otherwise finally disposed of within 30 days after the effective date of readjustment shall be valued pursuant to the provisions of § 206.257 of this subpart, and royalties shall be paid at the royalty rate specified in the readjusted lease.
[54 FR 1523, Jan. 13, 1989, as amended at 61 FR 5480, Feb. 12, 1996]
§ 206.257
Valuation standards for ad valorem leases.
(a) This section is applicable to coal leases on Federal lands which provide for the determination of royalty as a percentage of the amount of value of coal (ad valorem). The value for royalty purposes of coal from such leases shall be the value of coal determined under this section, less applicable coal washing allowances and transportation allowances determined under §§ 206.258 through 206.262 of this subpart, or any allowance authorized by § 206.265 of this subpart. The royalty due shall be equal to the value for royalty purposes multiplied by the royalty rate in the lease.
(b)(1) The value of coal that is sold pursuant to an arm's-length contract shall be the gross proceeds accruing to the lessee, except as provided in paragraphs (b)(2), (b)(3), and (b)(5) of this section. The lessee shall have the burden of demonstrating that its contract is arm's-length. The value which the lessee reports, for royalty purposes, is subject to monitoring, review, and audit.
(2) In conducting reviews and audits, MMS will examine whether the contract reflects the total consideration actually transferred either directly or indirectly from the buyer to the seller for the coal produced. If the contract does not reflect the total consideration, then the MMS may require that the coal sold pursuant to that contract be valued in accordance with paragraph (c) of this section. Value may not be based on less than the gross proceeds accruing to the lessee for the coal production, including the additional consideration.
(3) If the MMS determines that the gross proceeds accruing to the lessee pursuant to an arm's-length contract do not reflect the reasonable value of the production because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then MMS shall require that the coal production be valued pursuant to paragraph (c)(2) (ii), (iii), (iv), or (v) of this section, and in accordance with the notification requirements of paragraph (d)(3) of this section. When MMS determines that the value may be unreasonable, MMS will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's reported coal value.
(4) The MMS may require a lessee to certify that its arm's-length contract provisions include all of the consideration to be paid by the buyer, either directly or indirectly, for the coal production.
(5) The value of production for royalty purposes shall not include payments received by the lessee pursuant to a contract which the lessee demonstrates, to MMS's satisfaction, were not part of the total consideration paid for the purchase of coal production.
(c)(1) The value of coal from leases subject to this section and which is not sold pursuant to an arm's-length contract shall be determined in accordance with this section.
(2) If the value of the coal cannot be determined pursuant to paragraph (b) of this section, then the value shall be determined through application of other valuation criteria. The criteria shall be considered in the following order, and the value shall be based upon the first applicable criterion:
(i) The gross proceeds accruing to the lessee pursuant to a sale under its non-arm's-length contract (or other disposition of produced coal by other than an arm's-length contract), provided that those gross proceeds are within the range of the gross proceeds derived from, or paid under, comparable arm's-length contracts between buyers and sellers neither of whom is affiliated with the lessee for sales, purchases, or other dispositions of like-quality coal produced in the area. In evaluating the comparability of arm's-length contracts for the purposes of these regulations, the following factors shall be considered: Price, time of execution, duration, market or markets served, terms, quality of coal, quantity, and such other factors as may be appropriate to reflect the value of the coal;
(ii) Prices reported for that coal to a public utility commission;
(iii) Prices reported for that coal to the Energy Information Administration of the Department of Energy;
(iv) Other relevant matters including, but not limited to, published or publicly available spot market prices, or information submitted by the lessee concerning circumstances unique to a particular lease operation or the saleability of certain types of coal;
(v) If a reasonable value cannot be determined using paragraphs (c)(2) (i), (ii), (iii), or (iv) of this section, then a net-back method or any other reasonable method shall be used to determine value.
(3) When the value of coal is determined pursuant to paragraph (c)(2) of this section, that value determination shall be consistent with the provisions contained in paragraph (b)(5) of this section.
(d)(1) Where the value is determined pursuant to paragraph (c) of this section, that value does not require MMS's prior approval. However, the lessee shall retain all data relevant to the determination of royalty value. Such data shall be subject to review and audit, and MMS will direct a lessee to use a different value if it determines that the reported value is inconsistent with the requirements of these regulations.
(2) Any Federal lessee will make available upon request to the authorized MMS or State representatives, to the Inspector General of the Department of the Interior or other persons authorized to receive such information, arm's-length sales value and sales quantity data for like-quality coal sold, purchased, or otherwise obtained by the lessee from the area.
(3) A lessee shall notify MMS if it has determined value pursuant to paragraphs (c)(2) (ii), (iii), (iv), or (v) of this section. The notification shall be by letter to the Associate Director for Minerals Revenue Management of his/her designee. The letter shall identify the valuation method to be used and contain a brief description of the procedure to be followed. The notification required by this section is a one-time notification due no later than the month the lessee first reports royalties on the Form MMS-4430 using a valuation method authorized by paragraphs (c)(2) (ii), (iii), (iv), or (v) of this section, and each time there is a change in a method under paragraphs (c)(2) (iv) or (v) of this section.
(e) If MMS determines that a lessee has not properly determined value, the lessee shall be liable for the difference, if any, between royalty payments made based upon the value it has used and the royalty payments that are due based upon the value established by MMS. The lessee shall also be liable for interest computed pursuant to 30 CFR 218.202. If the lessee is entitled to a credit, MMS will provide instructions for the taking of that credit.
(f) The lessee may request a value determination from MMS. In that event, the lessee shall propose to MMS a value determination method, and may use that method in determining value for royalty purposes until MMS issues its decision. The lessee shall submit all available data relevant to its proposal. The MMS shall expeditiously determine the value based upon the lessee's proposal and any additional information MMS deems necessary. That determination shall remain effective for the period stated therein. After MMS issues its determination, the lessee shall make the adjustments in accordance with paragraph (e) of this section.
(g) Notwithstanding any other provisions of this section, under no circumstances shall the value for royalty purposes be less than the gross proceeds accruing to the lessee for the disposition of produced coal less applicable provisions of paragraph (b)(5) of this section and less applicable allowances determined pursuant to §§ 206.258 through 206.262 and § 206.265 of this subpart.
(h) The lessee is required to place coal in marketable condition at no cost to the Federal Government. Where the value established under this section is determined by a lessee's gross proceeds, that value shall be increased to the extent that the gross proceeds has been reduced because the purchaser, or any other person, is providing certain services, the cost of which ordinarily is the responsibility of the lessee to place the coal in marketable condition.
(i) Value shall be based on the highest price a prudent lessee can receive through legally enforceable claims under its contract. Absent contract revision or amendment, if the lessee fails to take proper or timely action to receive prices or benefits to which it is entitled, it must pay royalty at a value based upon that obtainable price or benefit. Contract revisions or amendments shall be in writing and signed by all parties to an arm's-length contract, and may be retroactively applied to value for royalty purposes for a period not to exceed two years, unless MMS approves a longer period. If the lessee makes timely application for a price increase allowed under its contract but the purchaser refuses, and the lessee takes reasonable measures, which are documented, to force purchaser compliance, the lessee will owe no additional royalties unless or until monies or consideration resulting from the price increase are received. This paragraph shall not be construed to permit a lessee to avoid its royalty payment obligation in situations where a purchaser fails to pay, in whole or in part or timely, for a quantity of coal.
(j) Notwithstanding any provision in these regulations to the contrary, no review, reconciliation, monitoring, or other like process that results in a redetermination by MMS of value under this section shall be considered final or binding as against the Federal Government or its beneficiaries until the audit period is formally closed.
(k) Certain information submitted to MMS to support valuation proposals, including transportation, coal washing, or other allowances under § 206.265 of this subpart, is exempted from disclosure by the Freedom of Information Act, 5 U.S.C. 522. Any data specified by the Act to be privileged, confidential, or otherwise exempt shall be maintained in a confidential manner in accordance with applicable law and regulations. All requests for information about determinations made under this part are to be submitted in accordance with the Freedom of Information Act regulation of the Department of the Interior, 43 CFR part 2.
[54 FR 1523, Jan. 13, 1989, as amended at 55 FR 35433, Aug. 30, 1990; 57 FR 52720, Nov. 5, 1992; 61 FR 5480, Feb. 12, 1996; 66 FR 45769, Aug. 30, 2001]
§ 206.258
Washing allowances—general.
(a) For ad valorem leases subject to § 206.257 of this subpart, MMS shall, as authorized by this section, allow a deduction in determining value for royalty purposes for the reasonable, actual costs incurred to wash coal, unless the value determined pursuant to § 206.257 of this subpart was based upon like-quality unwashed coal. Under no circumstances will the authorized washing allowance and the transportation allowance reduce the value for royalty purposes to zero.
(b) If MMS determines that a lessee has improperly determined a washing allowance authorized by this section, then the lessee shall be liable for any additional royalties, plus interest determined in accordance with 30 CFR 218.202, or shall be entitled to a credit without interest.
(c) Lessees shall not disproportionately allocate washing costs to Federal leases.
(d) No cost normally associated with mining operations and which are necessary for placing coal in marketable condition shall be allowed as a cost of washing.
(e) Coal washing costs shall only be recognized as allowances when the washed coal is sold and royalties are reported and paid.
[54 FR 1523, Jan. 13, 1989, as amended at 61 FR 5480, Feb. 12, 1996; 64 FR 43288, Aug. 10, 1999]
§ 206.259
Determination of washing allowances.
(a) Arm's-length contracts. (1) For washing costs incurred by a lessee under an arm's-length contract, the washing allowance shall be the reasonable actual costs incurred by the lessee for washing the coal under that contract, subject to monitoring, review, audit, and possible future adjustment. The lessee shall have the burden of demonstrating that its contract is arm's-length. MMS' prior approval is not required before a lessee may deduct costs incurred under an arm's-length contract. The lessee must claim a washing allowance by reporting it as a separate line entry on the Form MMS-4430.
(2) In conducting reviews and audits, MMS will examine whether the contract reflects more than the consideration actually transferred either directly or indirectly from the lessee to the washer for the washing. If the contract reflects more than the total consideration paid, then the MMS may require that the washing allowance be determined in accordance with paragraph (b) of this section.
(3) If the MMS determines that the consideration paid pursuant to an arm's-length washing contract does not reflect the reasonable value of the washing because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then MMS shall require that the washing allowance be determined in accordance with paragraph (b) of this section. When MMS determines that the value of the washing may be unreasonable, MMS will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's washing costs.
(4) Where the lessee's payments for washing under an arm's-length contract are not based on a dollar-per-unit basis, the lessee shall convert whatever consideration is paid to a dollar value equivalent. Washing allowances shall be expressed as a cost per ton of coal washed.
(b) Non-arm's-length or no contract. (1) If a lessee has a non-arm's-length contract or has no contract, including those situations where the lessee performs washing for itself, the washing allowance will be based upon the lessee's reasonable actual costs. All washing allowances deducted under a non-arm's-length or no contract situation are subject to monitoring, review, audit, and possible future adjustment. The lessee must claim a washing allowance by reporting it as a separate line entry on the Form MMS-4430. When necessary or appropriate, MMS may direct a lessee to modify its estimated or actual washing allowance.
(2) The washing allowance for non-arm's-length or no contract situations shall be based upon the lessee's actual costs for washing during the reported period, including operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment in accordance with paragraph (b)(2)(iv) (A) of this section, or a cost equal to the depreciable investment in the wash plant multiplied by the rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) which are an integral part of the wash plant.
(i) Allowable operating expenses include: Operations supervision and engineering; operations labor; fuel; utilities; materials; ad valorem property taxes, rent; supplies; and any other directly allocable and attributable operating expense which the lessee can document.
(ii) Allowable maintenance expenses include: Maintenance of the wash plant; maintenance of equipment; maintenance labor; and other directly allocable and attributable maintenance expenses which the lessee can document.
(iii) Overhead attributable and allocable to the operation and maintenance of the wash plant is an allowable expense. State and Federal income taxes and severance taxes, including royalities, are not allowable expenses.
(iv) A lessee may use either paragraph (b)(2)(iv)(A) or (B) of this section. After a lessee has elected to use either method for a wash plant, the lessee may not later elect to change to the other alternative without approval of the MMS.
(A) To compute depreciation, the lessee may elect to use either a straight-line depreciation method based on the life of equipment or on the life of the reserves which the wash plant services, whichever is appropriate, or a unit of production method. After an election is made, the lessee may not change methods without MMS approval. A change in ownership of a wash plant shall not alter the depreciation schedule established by the original operator/lessee for purposes of the allowance calculation. With or without a change in ownership, a wash plant shall be depreciated only once. Equipment shall not be depreciated below a reasonable salvage value.
(B) The MMS shall allow as a cost an amount equal to the allowable capital investment in the wash plant multiplied by the rate of return determined pursuant to paragraph (b)(2)(v) of this section. No allowance shall be provided for depreciation. This alternative shall apply only to plants first placed in service or acquired after March 1, 1989.
(v) The rate of return must be the industrial rate associated with Standard and Poor's BBB rating. The rate of return must be the monthly average rate as published in Standard and Poor's Bond Guide for the first month for which the allowance is applicable. The rate must be redetermined at the beginning of each subsequent calendar year.
(3) The washing allowance for coal shall be determined based on the lessee's reasonable and actual cost of washing the coal. The lessee may not take an allowance for the costs of washing lease production that is not royalty bearing.
(c) Reporting requirements—(1) Arm's-length contracts. (i) The lessee must notify MMS of an allowance based on incurred costs by using a separate line entry on the Form MMS-4430.
(ii) The MMS may require that a lessee submit arm's-length washing contracts and related documents. Documents shall be submitted within a reasonable time, as determined by MMS.
(2) Non-arm's-length or no contract. (i) The lessee must notify MMS of an allowance based on the incurred costs by using a separate line entry on the Form MMS-4430.
(ii) For new washing facilities or arrangements, the lessee's initial washing deduction shall include estimates of the allowable coal washing costs for the applicable period. Cost estimates shall be based upon the most recently available operations data for the washing system or, if such data are not available, the lessee shall use estimates based upon industry data for similar washing systems.
(iii) Upon request by MMS, the lessee shall submit all data used to prepare the allowance deduction. The data shall be provided within a reasonable period of time, as determined by MMS.
(d) Interest and assessments. (1) If a lessee nets a washing allowance on the Form MMS-4430, then the lessee shall be assessed an amount up to 10 percent of the allowance netted not to exceed $250 per lease sales type code per sales period.
(2) If a lessee erroneously reports a washing allowance which results in an underpayment of royalties, interest shall be paid on the amount of that underpayment.
(3) Interest required to be paid by this section shall be determined in accordance with 30 CFR 218.202.
(e) Adjustments. (1) If the actual coal washing allowance is less than the amount the lessee has taken on Form MMS-4430 for each month during the allowance reporting period, the lessee shall pay additional royalties due plus interest computed under 30 CFR 218.202 from the date when the lessee took the deduction to the date the lessee repays the difference to MMS. If the actual washing allowance is greater than the amount the lessee has taken on Form MMS-4430 for each month during the allowance reporting period, the lessee shall be entitled to a credit without interest.
(2) The lessee must submit a corrected Form MMS-4430 to reflect actual costs, together with any payment, in accordance with instructions provided by MMS.
(f) Other washing cost determinations. The provisions of this section shall apply to determine washing costs when establishing value using a net-back valuation procedure or any other procedure that requires deduction of washing costs.
[54 FR 1523, Jan. 13, 1989, as amended at 57 FR 52720, Nov. 5, 1992; 61 FR 5480, Feb. 12, 1996; 64 FR 43288, Aug. 10, 1999; 66 FR 45769, Aug. 30, 2001; 73 FR 15891, Mar. 26, 2008]
§ 206.260
Allocation of washed coal.
(a) When coal is subjected to washing, the washed coal must be allocated to the leases from which it was extracted.
(b) When the net output of coal from a washing plant is derived from coal obtained from only one lease, the quantity of washed coal allocable to the lease will be based on the net output of the washing plant.
(c) When the net output of coal from a washing plant is derived from coal obtained from more than one lease, unless determined otherwise by BLM, the quantity of net output of washed coal allocable to each lease will be based on the ratio of measured quantities of coal delivered to the washing plant and washed from each lease compared to the total measured quantities of coal delivered to the washing plant and washed.
§ 206.261
Transportation allowances—general.
(a) For ad valorem leases subject to § 206.257 of this subpart, where the value for royalty purposes has been determined at a point remote from the lease or mine, MMS shall, as authorized by this section, allow a deduction in determining value for royalty purposes for the reasonable, actual costs incurred to:
(1) Transport the coal from a Federal lease to a sales point which is remote from both the lease and mine; or
(2) Transport the coal from a Federal lease to a wash plant when that plant is remote from both the lease and mine and, if applicable, from the wash plant to a remote sales point. In-mine transportation costs shall not be included in the transportation allowance.
(b) Under no circumstances will the authorized washing allowance and the transportation allowance reduce the value for royalty purposes to zero.
(c)(1) When coal transported from a mine to a wash plant is eligible for a transportation allowance in accordance with this section, the lessee is not required to allocate transportation costs between the quantity of clean coal output and the rejected waste material. The transportation allowance shall be authorized for the total production which is transported. Transportation allowances shall be expressed as a cost per ton of cleaned coal transported.
(2) For coal that is not washed at a wash plant, the transportation allowance shall be authorized for the total production which is transported. Transportation allowances shall be expressed as a cost per ton of coal transported.
(3) Transportation costs shall only be recognized as allowances when the transported coal is sold and royalties are reported and paid.
(d) If, after a review and/or audit, MMS determines that a lessee has improperly determined a transportation allowance authorized by this section, then the lessee shall pay any additional royalties, plus interest, determined in accordance with 30 CFR 218.202, or shall be entitled to a credit, without interest.
(e) Lessees shall not disproportionately allocate transportation costs to Federal leases.
[54 FR 1523, Jan. 13, 1989, as amended at 61 FR 5481, Feb. 12, 1996; 64 FR 43288, Aug. 10, 1999]
§ 206.262
Determination of transportation allowances.
(a) Arm's-length contracts. (1) For transportation costs incurred by a lessee pursuant to an arm's-length contract, the transportation allowance shall be the reasonable, actual costs incurred by the lessee for transporting the coal under that contract, subject to monitoring, review, audit, and possible future adjustment. The lessee shall have the burden of demonstrating that its contract is arm's-length. The lessee must claim a transportation allowance by reporting it as a separate line entry on the Form MMS-4430.
(2) In conducting reviews and audits, MMS will examine whether the contract reflects more than the consideration actually transferred either directly or indirectly from the lessee to the transporter for the transportation. If the contract reflects more than the total consideration paid, then the MMS may require that the transportation allowance be determined in accordance with paragraph (b) of this section.
(3) If the MMS determines that the consideration paid pursuant to an arm's-length transportation contract does not reflect the reasonable value of the transportation because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then MMS shall require that the transportation allowance be determined in accordance with paragraph (b) of this section. When MMS determines that the value of the transportation may be unreasonable, MMS will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's transportation costs.
(4) Where the lessee's payments for transportation under an arm's-length contract are not based on a dollar-per-unit basis, the lessee shall convert whatever consideration is paid to a dollar value equivalent for the purposes of this section.
(b) Non-arm's-length or no contract—(1) If a lessee has a non-arm's-length contract or has no contract, including those situations where the lessee performs transportation services for itself, the transportation allowance will be based upon the lessee's reasonable actual costs. All transportation allowances deducted under a non-arm's-length or no contract situation are subject to monitoring, review, audit, and possible future adjustment. The lessee must claim a transportation allowance by reporting it as a separate line entry on the Form MMS-4430. When necessary or appropriate, MMS may direct a lessee to modify its estimated or actual transportation allowance deduction.
(2) The transportation allowance for non-arm's-length or no-contract situations shall be based upon the lessee's actual costs for transportation during the reporting period, including operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment in accordance with paragraph (b)(2)(iv)(A) of this section, or a cost equal to the depreciable investment in the transportation system multiplied by the rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) which are an integral part of the transportation system.
(i) Allowable operating expenses include: Operations supervision and engineering; operations labor; fuel; utilities; materials; ad valorem property taxes; rent; supplies; and any other directly allocable and attributable operating expense which the lessee can document.
(ii) Allowable maintenance expenses include: Maintenance of the transportation system; maintenance of equipment; maintenance labor; and other directly allocable and attributable maintenance expenses which the lessee can document.
(iii) Overhead attributable and allocable to the operation and maintenance of the transportation system is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses.
(iv) A lessee may use either paragraph (b)(2)(iv)(A) or paragraph (b)(2)(iv)(B) of this section. After a lessee has elected to use either method for a transportation system, the lessee may not later elect to change to the other alternative without approval of the MMS.
(A) To compute depreciation, the lessee may elect to use either a straight-line depreciation method based on the life of equipment or on the life of the reserves which the transportation system services, whichever is appropriate, or a unit of production method. After an election is made, the lessee may not change methods without MMS approval. A change in ownership of a transportation system shall not alter the depreciation schedule established by the original transporter/lessee for purposes of the allowance calculation. With or without a change in ownership, a transportation system shall be depreciated only once. Equipment shall not be depreciated below a reasonable salvage value.
(B) The MMS shall allow as a cost an amount equal to the allowable capital investment in the transportation system multiplied by the rate of return determined pursuant to paragraph (b)(2)(B)(v) of this section. No allowance shall be provided for depreciation. This alternative shall apply only to transportation facilities first placed in service or acquired after March 1, 1989.
(v) The rate of return must be the industrial rate associated with Standard and Poor's BBB rating. The rate of return must be the monthly average rate as published in Standard and Poor's Bond Guide for the first month for which the allowance is applicable. The rate must be redetermined at the beginning of each subsequent calendar year.
(3) A lessee may apply to MMS for exception from the requirement that it compute actual costs in accordance with paragraphs (b)(1) and (b)(2) of this section. MMS will grant the exception only if the lessee has a rate for the transportation approved by a Federal agency or by a State regulatory agency (for Federal leases). MMS shall deny the exception request if it determines that the rate is excessive as compared to arm's-length transportation charges by systems, owned by the lessee or others, providing similar transportation services in that area. If there are no arm's-length transportation charges, MMS shall deny the exception request if:
(i) No Federal or State regulatory agency costs analysis exists and the Federal or State regulatory agency, as applicable, has declined to investigate under MMS timely objections upon filing; and
(ii) The rate significantly exceeds the lessee's actual costs for transportation as determined under this section.
(c) Reporting requirements—(1) Arm's-length contracts. (i) The lessee must notify MMS of an allowance based on incurred costs by using a separate line entry on the Form MMS-4430.
(ii) The MMS may require that a lessee submit arm's-length transportation contracts, production agreements, operating agreements, and related documents. Documents shall be submitted within a reasonable time, as determined by MMS.
(2) Non-arm's-length or no contract—(i) The lessee must notify MMS of an allowance based on the incurred costs by using a separate line entry on Form MMS-4430.
(ii) For new transportation facilities or arrangements, the lessee's initial deduction shall include estimates of the allowable coal transportation costs for the applicable period. Cost estimates shall be based upon the most recently available operations data for the transportation system or, if such data are not available, the lessee shall use estimates based upon industry data for similar transportation systems.
(iii) Upon request by MMS, the lessee shall submit all data used to prepare the allowance deduction. The data shall be provided within a reasonable period of time, as determined by MMS.
(iv) If the lessee is authorized to use its Federal- or State-agency-approved rate as its transportation cost in accordance with paragraph (b)(3) of this section, it shall follow the reporting requirements of paragraph (c)(1) of this section.
(d) Interest and assessments. (1) If a lessee nets a transportation allowance on Form MMS-4430, the lessee shall be assessed an amount of up to 10 percent of the allowance netted not to exceed $250 per lease sales type code per sales period.
(2) If a lessee erroneously reports a transportation allowance which results in an underpayment of royalties, interest shall be paid on the amount of that underpayment.
(3) Interest required to be paid by this section shall be determined in accordance with 30 CFR 218.202.
(e) Adjustments. (1) If the actual coal transportation allowance is less than the amount the lessee has taken on Form MMS-4430 for each month during the allowance reporting period, the lessee shall pay additional royalties due plus interest computed under 30 CFR 218.202 from the date when the lessee took the deduction to the date the lessee repays the difference to MMS. If the actual transportation allowance is greater than amount the lessee has taken on Form MMS-4430 for each month during the allowance reporting period, the lessee shall be entitled to a credit without interest.
(2) The lessee must submit a corrected Form MMS-4430 to reflect actual costs, together with any payments, in accordance with instructions provided by MMS.
(f) Other transportation cost determinations. The provisions of this section shall apply to determine transportation costs when establishing value using a net-back valuation procedure or any other procedure that requires deduction of transportation costs.
[54 FR 1523, Jan. 13, 1989, as amended at 57 FR 41864, Sept. 14, 1992; 57 FR 52720, Nov. 5, 1992; 61 FR 5481, Feb. 12, 1996; 64 FR 43288, Aug. 10, 1999; 66 FR 45769, Aug. 30, 2001; 73 FR 15891, Mar. 26, 2008]
§ 206.263
[Reserved]
§ 206.264
In-situ and surface gasification and liquefaction operations.
If an ad valorem Federal coal lease is developed by in-situ or surface gasification or liquefaction technology, the lessee shall propose the value of coal for royalty purposes to MMS. The MMS will review the lessee's proposal and issue a value determination. The lessee may use its proposed value until MMS issues a value determination.
[54 FR 1523, Jan. 13, 1989, as amended at 65 FR 43289, Aug. 10, 1999]
§ 206.265
Value enhancement of marketable coal.
If, prior to use, sale, or other disposition, the lessee enhances the value of coal after the coal has been placed in marketable condition in accordance with § 206.257(h) of this subpart, the lessee shall notify MMS that such processing is occurring or will occur. The value of that production shall be determined as follows:
(a) A value established for the feedstock coal in marketable condition by application of the provisions of § 206.257(c)(2)(i-iv) of this subpart; or,
(b) In the event that a value cannot be established in accordance with subsection (a), then the value of production will be determined in accordance with § 206.257(c)(2)(v) of this subpart and the value shall be the lessee's gross proceeds accruing from the disposition of the enhanced product, reduced by MMS-approved processing costs and procedures including a rate of return on investment equal to two times the Standard and Poor's BBB bond rate applicable under § 206.259(b)(2)(v) of this subpart.

Subpart G—Other Solid Minerals
§ 206.301
Value basis for royalty computation.
(a) The gross value for royalty purposes shall be the sale or contract unit price times the number of units sold, Provided, however, That where the authorized officer determines:
(1) That a contract of sale or other business arrangement between the lessee and a purchaser of some or all of the commodities produced from the lease is not a bona fide transaction between independent parties because it is based in whole or in part upon considerations other than the value of the commodities, or
(2) That no bona fide sales price is received for some or all of such commodities because the lessee is consuming them, the authorized officer shall determine their gross value, taking into account: (i) All prices received by the lessee in all bona fide transactions, (ii) Prices paid for commodities of like quality produced from the same general area, and (iii) Such other relevant factors as the authorized officer may deem appropriate; and Provided further, That in a situation where an estimated value is used, the authorized officer shall require the payment of such additional royalties, or allow such credits or refunds as may be necessary to adjust royalty payment to reflect the actual gross value.
(b) The lessee is required to certify that the values reported for royalty purposes are bona fide sales not involving considerations other than the sale of the mineral, and he may be required by the authorized officer to supply supporting information.
[43 FR 10341, Mar. 13, 1978. Redesignated at 48 FR 36588, Aug. 12, 1983, and amended at 48 FR 44795, Sept. 30, 1983. Further redesignated at 51 FR 15212, Apr. 22, 1986. Redesignated at 53 FR 39461, Oct. 7, 1988]

Subpart H—Geothermal Resources

Source:
72 FR 24459, May 2, 2007, unless otherwise noted.
§ 206.350
What is the purpose of this subpart?
(a) This subpart applies to all geothermal resources produced from Federal geothermal leases issued pursuant to the Geothermal Steam Act of 1970 (GSA), as amended by the Energy Policy Act of 2005 (EPAct) (30 U.S.C. 1001 et seq.). The purpose of this subpart is to prescribe how to calculate royalties and direct use fees for geothermal production.
(b) The MMS may audit and adjust all royalty and fee payments.
(c) In some cases, the regulations in this subpart may be inconsistent with a statute, settlement agreement, written agreement, or lease provision. If this happens, the statute, settlement agreement, written agreement, or lease provision will govern to the extent of the inconsistency. For purposes of this paragraph, the following definitions apply:
(1) “Settlement agreement” means a settlement agreement between the United States and a lessee resulting from administrative or judicial litigation.
(2) “Written agreement” means a written agreement between the lessee and the MMS Director or Assistant Secretary, Land and Minerals Management of the Department of the Interior that:
(i) Establishes a method to determine the royalty from any lease that MMS expects at least would approximate the value or royalty established under this subpart; and
(ii) Includes a value or gross proceeds determination under § 206.364 of this subpart.
§ 206.351
What definitions apply to this subpart?
For purposes of this subpart, the following terms have the meanings indicated.
Affiliate means a person who controls, is controlled by, or is under common control with another person. For purposes of this subpart:
(1) Ownership or common ownership of more than 50 percent of the voting securities, or instruments of ownership, or other forms of ownership, of another person constitutes control. Ownership of less than 10 percent constitutes a presumption of noncontrol that MMS may rebut.
(2) If there is ownership or common ownership of 10 through 50 percent of the voting securities, or instruments of ownership, or other forms of ownership of another person, MMS will consider the following factors in determining whether there is control under the circumstances of a particular case:
(i) The extent to which there are common officers or directors;
(ii) With respect to the voting securities, or instruments of ownership, or other forms of ownership: the percentage of ownership or common ownership, the relative percentage of ownership or common ownership compared to the percentage(s) of ownership by other persons, whether a person is the greatest single owner, or whether there is an opposing voting bloc of greater ownership;
(iii) Operation of a lease, plant, pipeline, or other facility;
(iv) The extent of participation by other owners in operations and day-to-day management of a lease, plant, pipeline, or other facility; and
(v) Other evidence of power to exercise control over or common control with another person.
(3) Regardless of any percentage of ownership or common ownership, relatives, either by blood or marriage, are affiliates.
Allowance means a deduction in determining value for royalty purposes.
Arm's-length contract means a contract or agreement between independent persons who are not affiliates and who have opposing economic interests regarding that contract. To be considered arm's length for any production month, a contract must satisfy this definition for that month, as well as when the contract was executed.
Audit means a review, conducted in accordance with generally accepted accounting and auditing standards, of royalty or fee payment compliance activities of lessees or other interest holders who pay royalties, fees, rents, or bonuses on Federal geothermal leases.
Byproducts means minerals (exclusive of oil, hydrocarbon gas, and helium), found in solution or in association with geothermal steam, that no person would extract and produce by themselves because they are worth less than 75 percent of the value of the geothermal steam or because extraction and production would be too difficult.
Byproduct recovery facility means a facility where byproducts are placed in marketable condition.
Byproduct transportation allowance means an allowance for the reasonable, actual costs of moving byproducts to a point of sale or delivery off the lease, unit area, or communitized area, or away from a byproduct recovery facility. The byproduct transportation allowance does not include gathering costs. You must report a byproduct transportation allowance as a separate discrete field on the Form MMS-2014.
Class I lease means:
(1) A lease that BLM issued before August 8, 2005, for which the lessee has not converted the royalty rate terms under 43 CFR 3212.25; or
(2) A lease that BLM issued in response to an application that was pending on August 8, 2005, for which the lessee has not made an election under 43 CFR 3200.8(b).
Class II lease means:
A lease that BLM issued after August 8, 2005, except for a lease issued in response to an application that was pending on August 8, 2005, for which the lessee does not make an election under 43 CFR 3200.8(b).
Class III lease means:
A lease that BLM issued before August 8, 2005, for which the lessee has converted to the royalty rate or direct use fee terms under 43 CFR 3212.25.
Commercial production or generation of electricity means generation of electricity that is sold or is subject to sale, including the electricity or energy that is reasonably required to produce the resource used in production of electricity for sale or to convert geothermal energy into electrical energy for sale.
Contract means any oral or written agreement, including amendments or revisions thereto, between two or more persons and enforceable by law that with due consideration creates an obligation.
Deduction means a subtraction the lessee uses to determine the value of geothermal resources produced from a Class I lease that the lessee uses to generate electricity.
Delivered electricity means the amount of electricity in kilowatt-hours delivered to the purchaser.
Direct use means the utilization of geothermal resources for commercial, residential, agricultural, public facilities, or other energy needs, other than the commercial production or generation of electricity.
Direct use facility means a facility that uses the heat or other energy of the geothermal resource for direct use purposes.
Electrical facility means a power plant or other facility that uses a geothermal resource to generate electricity.
Field means the land surface vertically projected over a subsurface geothermal reservoir encompassing at least the outermost boundaries of all geothermal accumulations known to be within that reservoir. Geothermal fields are usually given names and their official boundaries are often designated by regulatory agencies in the respective States in which the fields are located.
Gathering means the movement of lease production from the wellhead to the point of utilization.
Generating deduction means a deduction for the lessee's reasonable, actual costs of generating plant tailgate electricity.
Geothermal resources means:
(1) All products of geothermal processes, including indigenous steam, hot water, and hot brines;
(2) Steam and other gases, hot water, and hot brines resulting from water, gas, or other fluids artificially introduced into geothermal formations;
(3) Heat or other associated energy found in geothermal formations; and
(4) Any byproducts.
Gross proceeds (for royalty payment purposes) means the total monies and other consideration accruing to a geothermal lessee for the sale of electricity or geothermal resource. Gross proceeds includes, but is not limited to:
(1) Payments to the lessee for certain services such as effluent injection, field operation and maintenance, drilling or workover of wells, or field gathering to the extent that the lessee is obligated to perform such functions at no cost to the Federal Government;
(2) Reimbursements for production taxes and other taxes. Tax reimbursements are part of gross proceeds accruing to a lessee even though the Federal royalty interest may be exempt from taxation; and
(3) Any monies and other consideration, including the forms of consideration identified in this paragraph, to which a lessee is contractually or legally entitled but which it does not seek to collect through reasonable efforts.
Lease means a geothermal lease issued under the authority of the GSA, unless the context indicates otherwise.
Lessee (you) means any person to whom the United States issues a geothermal lease, and any person who has been assigned an obligation to make royalty, fee, or other payments required by the lease. This includes any person who has an interest in a geothermal lease as well as an operator or payor who has no interest in the lease but who has assumed the royalty, fee, or other payment responsibility. This also includes any affiliate of the lessee that uses the geothermal resource to generate electricity, in a direct use process, or to recover byproducts, or any affiliate that sells or transports lease production.
Marketable condition means lease products that are sufficiently free from impurities and otherwise in a condition that they will be accepted by a purchaser under a sales contract typical for the disposition from the field or area of such lease products.
Person means any individual, firm, corporation, association, partnership, consortium, or joint venture (when established as a separate entity).
Plant parasitic electricity means electricity used to operate a power plant that is used for commercial production or generation of electricity.
Plant tailgate electricity means the amount of electricity in kilowatt-hours generated by a power plant exclusive of plant parasitic electricity, but inclusive of any electricity generated by the power plant and returned to the lease for lease operations. Plant tailgate electricity should be measured at, or calculated for, the high voltage side of the transformer in the plant switchyard.
Point of utilization means the power plant or direct use facility in which the geothermal resource is utilized.
Public purpose means a program carried out by a State, tribal, or local government for the purpose of providing facilities or services for the benefit of the public in connection with, but not limited to, public health, safety or welfare, other than the commercial generation of electricity. Use of lands or facilities for habitation, cultivation, trade or manufacturing is permissible only when necessary for and integral to (i.e., an essential part of) the public purpose.
Public safety or welfare means a program carried out or promoted by a public agency for public purposes involving, directly or indirectly, protection, safety, and law enforcement activities, and the criminal justice system of a given political area. Public safety or welfare may include, but is not limited to, programs carried out by:
(1) Public police departments;
(2) Sheriffs' offices;
(3) The courts;
(4) Penal and correctional institutions (including juvenile facilities);
(5) State and local civil defense organizations; and
(6) Fire departments and rescue squads (including volunteer fire departments and rescue squads supported in whole or in part with public funds).
Reasonable alternative fuel means a conventional fuel (such as coal, oil, gas, or wood) that would normally be used as a source of heat in direct use operations.
Secretary means the Secretary of the Interior or any person duly authorized to exercise the powers vested in that office.
Transmission deduction means a deduction for the lessee's reasonable actual costs incurred to wheel or transmit the electricity from the lessee's power plant to the purchaser's delivery point.
Wheeling means the transmission of electricity from a power plant to the point of delivery.
§ 206.352
How do I calculate the royalty due on geothermal resources used for commercial production or generation of electricity?
(a) If you sold geothermal resources produced from a Class I, II, or III lease at arm's length that the purchaser uses to generate electricity, then the royalty on the geothermal resources is the gross proceeds accruing to you from the sale of the geothermal resource to the arm's-length purchaser multiplied by either:
(1) The royalty rate in your lease; or
(2) The royalty rate that BLM prescribes or calculates under 43 CFR 3211.17. See § 206.361 for additional provisions applicable to determining gross proceeds under arm's-length sales.
(b) If you use the geothermal resource in your own power plant for the generation and sale of electricity, the following provisions apply
(1) For Class I leases, you must determine the royalty on produced geothermal resources in accordance with the first applicable of the following paragraphs:
(i) The gross proceeds accruing to you from the arm's-length sale of the electricity less applicable deductions determined under § 206.353 and § 206.354 of this part, multiplied by the royalty rate in your lease. See § 206.361 for additional provisions applicable to determining gross proceeds under arm's-length sales. Under no circumstances may the deductions reduce the royalty value of the geothermal resource to zero; or
(ii) A royalty determined by any other reasonable method approved by MMS under § 206.364 of this subpart.
(2) For Class II and Class III leases, the royalty on geothermal resources produced is your gross proceeds from the sale of electricity multiplied by the royalty rate BLM prescribed for your lease under 43 CFR 3211.17. See § 206.361 for additional provisions applicable to determining gross proceeds under arm's-length sales. You may not reduce gross proceeds by any deductions.
§ 206.353
How do I determine transmission deductions?
(a) If you determine the value of your geothermal resources under § 206.352(b)(1)(i) of this subpart, you may subtract a transmission deduction from the gross proceeds you received for the sale of electricity to determine the plant tailgate value of the electricity.
(1) The transmission deduction consists of either or both of two components:
(i) Transmission line costs as determined under paragraph (b) of this section; and
(ii) Wheeling costs if the electricity is transmitted across a third party's transmission line under an arm's-length wheeling agreement.
(2) You may deduct the actual costs you (including your affiliate(s)) incur for transmitting electricity under your arm's-length wheeling contract.
(b) To determine your transmission line cost, you must follow the requirements of paragraphs (b)(1) and (b)(2) of this section.
(1) Your transmission line costs are your actual costs associated with the construction and operation of a transmission line for the purpose of transmitting electricity attributable and allocable to your power plant utilizing Federal geothermal resources.
(i) You must determine the monthly transmission line cost component of the transmission deduction by multiplying the annual transmission line cost rate (in dollars per kilowatt-hour) by the amount of electricity delivered for the reporting month.
(ii) You must redetermine the transmission line cost rate annually either at the beginning of the same month of the year in which the power plant was placed into service or at a time concurrent with the beginning of your annual corporate accounting period. The period you select must coincide with the same period you chose for the generating deduction under § 206.354(b)(1). After you choose a deduction period, you may not later elect to use a different deduction period without MMS approval.
(2) Your actual transmission line costs during the reporting period include:
(i) Operating and maintenance expenses under paragraphs (d) and (e) of this section;
(ii) Overhead under paragraph (f) of this section; and either
(iii) Depreciation under paragraphs (g) and (h) of this section and a return on undepreciated capital investment under paragraphs (g) and (i) of this section or
(iv) A return on the capital investment in the transmission line under paragraphs (g) and (j) of this section.
(c)(1) Allowable capital costs under paragraph (b) of this section are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) that are an integral part of the transmission line.
(2)(i) You may include a return on capital you invested in the purchase of real estate for transmission facilities if:
(A) Such purchase is necessary; and
(B) The surface is not part of the Federal lease.
(ii) The rate of return will be the same rate determined under paragraph (k) of this section.
(d) Allowable operating expenses include:
(1) Operations supervision and engineering;
(2) Operations labor;
(3) Fuel;
(4) Utilities;
(5) Materials;
(6) Ad valorem property taxes;
(7) Rent;
(8) Supplies; and
(9) Any other directly allocable and attributable operating or maintenance expense that you can document.
(e) Allowable maintenance expenses include:
(1) Maintenance of the transmission line;
(2) Maintenance of equipment;
(3) Maintenance labor; and
(4) Other directly allocable and attributable maintenance expenses that you can document.
(f) Overhead directly attributable and allocable to the operation and maintenance of the transmission line is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses.
(g) To compute costs associated with capital investment, a lessee may use either depreciation with a return on undepreciated capital investment, or a return on capital investment in the transmission line. After a lessee has elected to use either method, the lessee may not later elect to change to the other alternative without MMS approval.
(h)(1) To compute depreciation, you must use a straight-line depreciation method based on the life of the geothermal project, usually the term of the electricity sales contract, or other depreciation period acceptable to MMS. You may not depreciate equipment below a reasonable salvage value.
(2) A change in ownership of a transmission line does not alter the depreciation schedule established by the original lessee-owner for purposes of computing transmission line costs.
(3) With or without a change in ownership, you may depreciate a transmission line only once.
(i) To calculate a return on undepreciated capital investment, multiply the remaining undepreciated capital balance as of the beginning of the period for which you are calculating the transmission deduction by the rate of return provided in paragraph (k) of this section.
(j) To compute a return on capital investment in the transmission line, multiply the allowable capital investment in the transmission line by the rate of return determined pursuant to paragraph (k) of this section. There is no allowance for depreciation.
(k) The rate of return must be 2.0 multiplied by the industrial rate associated with Standard & Poor's BBB rating. The BBB rate must be the monthly average rate as published in Standard & Poor's Bond Guide for the first month for which the allowance is applicable. Redetermine the rate at the beginning of each subsequent calendar year.
(l) Calculate the deduction for transmission costs based on your cost of transmitting electricity through each individual transmission line.
(m)(1) For new transmission facilities or arrangements, base your initial deduction on estimates of allowable electricity transmission costs for the applicable period. Use the most recently available operations data for the transmission line or, if such data are not available, use estimates based on data for similar transmission lines.
(2) When actual cost information is available, you must amend your prior Form MMS-2014 reports to reflect actual transmission costs deductions for each month for which you reported and paid based on estimated transmission costs. You must pay any additional royalties due (together with interest computed under § 218.302). You are entitled to a credit for or refund of any overpaid royalties.
(n) In conducting reviews and audits, MMS may require you to submit arm's-length transmission contracts, production agreements, operating agreements, and related documents and all other data used to calculate the deduction. You must comply with any such requirements within the time MMS specifies. Recordkeeping requirements are found at part 212 of this chapter.
(o) At the completion of transmission line dismantlement and salvage operations, you may report a credit for or request a refund of royalties in an amount equal to the royalty rate times the amount by which actual transmission line dismantlement costs exceed actual income attributable to salvage of the transmission line.
§ 206.354
How do I determine generating deductions?
(a) If you determine the value of your geothermal resources under § 206.352(b)(1)(i) of this subpart, you may deduct your reasonable actual costs incurred to generate electricity from the plant tailgate value of the electricity (usually the transmission-reduced value of the delivered electricity). You may deduct the actual costs you incur for generating electricity under your arm's-length power plant contract.
(b)(1) You must base your generating costs deduction on your actual annual costs associated with the construction and operation of a geothermal power plant.
(i) You must determine your monthly generating deduction by multiplying the annual generating cost rate (in dollars per kilowatt-hour) by the amount of plant tailgate electricity measured (or computed) for the reporting month. The generating cost rate is determined from the annual amount of your plant tailgate electricity.
(ii) You must redetermine your generating cost rate annually either at the beginning of the same month of the year in which the power plant was placed into service or at a time concurrent with the beginning of your annual corporate accounting period. The period you select must coincide with the same period chosen for the transmission deduction under § 206.353(b)(1). After you choose a deduction period, you may not later elect to use a different deduction period without MMS approval.
(2) Your generating costs are your actual power plant costs during the reporting period, including:
(i) Operating and maintenance expenses under paragraphs (d) and (e) of this section;
(ii) Overhead under paragraph (f) of this section; and either
(iii) Depreciation under paragraphs (g) and (h) of this section and a return on undepreciated capital investment under paragraphs (g) and (i) of this section; or
(iv) A return on capital investment in the power plant under paragraphs (g) and (j) of this section.
(c)(1) Allowable capital costs under paragraph (b) of this section are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) that are an integral part of the power plant or are required by the design specifications of the power conversion cycle.
(2)(i) You may include a return on capital you invested in the purchase of real estate for a power plant site if:
(A) The purchase is necessary; and,
(B) The surface is not part of the Federal lease.
(ii) The rate of return will be the same rate determined under paragraph (k) of this section.
(3) You may not deduct the costs of gathering systems and other production-related facilities.
(d) Allowable operating expenses include:
(1) Operations supervision and engineering;
(2) Operations labor;
(3) Auxiliary fuel and/or utilities used to operate the power plant during down time;
(4) Utilities;
(5) Materials;
(6) Ad valorem property taxes;
(7) Rent;
(8) Supplies; and
(9) Any other directly allocable and attributable operating expense.
(e) Allowable maintenance expenses include:
(1) Maintenance of the power plant;
(2) Maintenance of equipment;
(3) Maintenance labor; and
(4) Other directly allocable and attributable maintenance expenses that you can document.
(f) Overhead directly attributable and allocable to the operation and maintenance of the power plant is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses.
(g) To compute costs associated with capital investment, a lessee may use either depreciation with a return on undepreciated capital investment, or a return on capital investment in the power plant. After a lessee has elected to use either method, the lessee may not later elect to change to the other alternative without MMS approval.
(h)(1) To compute depreciation, you must use a straight-line depreciation method based on the life of the geothermal project, usually the term of the electricity sales contract, or other depreciation period acceptable to MMS. You may not depreciate equipment below a reasonable salvage value.
(2) A change in ownership of the power plant does not alter the depreciation schedule established by the original lessee-owner for purposes of computing generating costs.
(3) With or without a change in ownership, you may depreciate a power plant only once.
(i) To calculate a return on undepreciated capital investment, multiply the remaining undepreciated capital balance as of the beginning of the period for which you are calculating the generating deduction allowance by the rate of return provided in paragraph (k) of this section.
(j) To compute a return on capital investment in the power plant, multiply the allowable capital investment in the power plant by the rate of return determined pursuant to paragraph (k) of this section. There is no allowance for depreciation.
(k) The rate of return must be 2.0 multiplied by the industrial rate associated with Standard & Poor's BBB rating. The BBB rate must be the monthly average rate as published in Standard & Poor's Bond Guide for the first month for which the allowance is applicable. You must redetermine the rate at the beginning of each subsequent calendar year.
(l) Calculate the deduction for generating costs based on your cost of generating electricity through each individual power plant.
(m)(1) For new power plants or arrangements, base your initial deduction on estimates of allowable electricity generation costs for the applicable period. Use the most recently available operations data for the power plant or, if such data are not available, use estimates based on data for similar power plants.
(2) When actual cost information is available, you must amend your prior Form MMS-2014 reports to reflect actual generating cost deductions for each month for which you reported and paid based on estimated generating costs. You must pay any additional royalties due (together with interest computed under § 218.302). You are entitled to a credit for or refund of any overpaid royalties.
(n) In conducting reviews and audits, MMS may require you to submit arm's-length power plant contracts, production agreements, operating agreements, related documents and all other data used to calculate the deduction. You must comply with any such requirements within the time MMS specifies. Recordkeeping requirements are found at part 212 of this chapter.
(o) At the completion of power plant dismantlement and salvage operations, you may report a credit for or request a refund of royalty in an amount equal to the royalty rate times the amount by which actual power plant dismantlement costs exceed actual income attributable to salvage of the power plant.
§ 206.355
How do I calculate royalty due on geothermal resources I sell at arm's length to a purchaser for direct use?
If you sell geothermal resources produced from Class I, II, or III leases at arm's length to a purchaser for direct use, then the royalty on the geothermal resource is the gross proceeds accruing to you from the sale of the geothermal resource to the arm's-length purchaser multiplied by the royalty rate in your lease or that BLM prescribes under 43 CFR 3211.18. See § 206.361 for additional provisions applicable to determining gross proceeds under arm's-length sales.
§ 206.356
How do I calculate royalty or fees due on geothermal resources I use for direct use purposes?
If you use the geothermal resource for direct use:
(a) For Class I leases, you must determine the royalty due on geothermal resources in accordance with the first applicable of the following three paragraphs.
(1) The weighted average of the gross proceeds established in arm's-length contracts for the purchase of significant quantities of geothermal resources to operate the lessee's same direct-use facility multiplied by the royalty rate in your lease. In evaluating the acceptability of arm's-length contracts, the following factors will be considered: time of execution, duration, terms, volume, quality of resource, and such other factors as may be appropriate to reflect the value of the resource.
(2) The equivalent value of the least expensive, reasonable alternative energy source (fuel) multiplied by the royalty rate in your lease. The equivalent value of the least expensive, reasonable alternative energy source will be based on the amount of thermal energy that would otherwise be used by the direct use facility in place of the geothermal resource. That amount of thermal energy (in Btu) displaced by the geothermal resource will be determined by the equation:
Where hin is the enthalpy in Btu/lb at the direct use facility inlet (based on measured inlet temperature), hout is the enthalpy in Btu/lb at the facility outlet (based on measured outlet temperature), density is in lbs/cu ft based on inlet temperature, the factor 0.113681 (cu ft/gal) converts gallons to cubic feet, and volume is the quantity of geothermal fluid in gallons produced at the wellhead or measured at an approved point. The efficiency factor of the alternative energy source will be 0.7 for coal and 0.8 for oil, natural gas, and other fuels derived from oil and natural gas, or an efficiency factor proposed by the lessee and approved by MMS. The methods of measuring resource parameters (temperature, volume, etc.) and the frequency of computing and accumulating the amount of thermal energy displaced will be determined and approved by BLM under 43 CFR 3275.13-3275.17.
(3) A royalty determined by any other reasonable method approved by MMS or the Assistant Secretary, Land and Minerals Management of the Department of the Interior, under § 206.364 of this part.
(b) For geothermal resources produced from Class II and Class III leases, you must multiply the appropriate fee from the schedule in subparagraph (b)(1) of this section by the number of gallons or pounds you produce from the direct use lease each month.
(1) You must use the following fee schedule to calculate fees due under this section:
Direct Use Fee Schedule
[Hot water]
If your average monthly inlet temperature ( °F) is | At least . . . | But less than . . . | Your fees are . . . | ($/million gallons) | ($/million pounds)
130 | 140 | 2.524 | 0.307
140 | 150 | 7.549 | 0.921
150 | 160 | 12.543 | 1.536
160 | 170 | 17.503 | 2.150
170 | 180 | 22.426 | 2.764
180 | 190 | 27.310 | 3.379
190 | 200 | 32.153 | 3.993
200 | 210 | 36.955 | 4.607
210 | 220 | 41.710 | 5.221
220 | 230 | 46.417 | 5.836
230 | 240 | 51.075 | 6.450
240 | 250 | 55.682 | 7.064
250 | 260 | 60.236 | 7.679
260 | 270 | 64.736 | 8.293
| 270 | 280 | 69.176 | 8.907
280 | 290 | 73.558 | 9.521
290 | 300 | 77.876 | 10.136
300 | 310 | 82.133 | 10.750
310 | 320 | 86.328 | 11.364
320 | 330 | 90.445 | 11.979
330 | 340 | 94.501 | 12.593
340 | 350 | 98.481 | 13.207
350 | 360 | 102.387 | 13.821
(i) For direct use geothermal resources with an average monthly inlet temperature of 130 °F or less, you must pay only the lease rental.
(ii) The MMS, in consultation with BLM, will develop and publish a revised fee schedule in the Federal Register, as needed.
(iii) The MMS, in consultation with BLM, will calculate revised fees schedules using the following formulas:
Where:
RV = Royalty due as a function of produced volume in the fee schedule, expressed as dollars per million (10^6) gallons;
Rm = Royalty due as a function of produced mass in the fee schedule, expressed as dollars per million (10^6) pounds;
ρ[rho] = Water density at inlet temperature expressed as lbs per gallon;
Tin = Measured inlet temperature in °F (as required by BLM under 43 CFR part 3275);
Tout = Established assumed outlet temperature of 130° F;
e = Boiler Efficiency Factor for coal of 70 percent;
Pprbc = The 3-year historical average of Powder River Basin spot coal prices, as published by the Energy Information Administration, or other recognized authoritative reference source of coal prices, in dollars (per MMBtu);
Frr = The assumed Lease Royalty Rate of 10 percent.
(2) The fee that you report is subject to monitoring, review, and audit.
(3) The schedule of fees established under this paragraph will apply to any Class III lease with respect to any royalty payments previously made when the lease was a Class I lease that were due and owing, and were paid, on or after July 16, 2003. To use this provision, you must provide MMS data showing the amount of geothermal production in pounds or gallons of geothermal fluid to input into the fee schedule (see 43 CFR part 3276).
(i) If the royalties you previously paid are less than the fees due under this section, you must pay the difference plus interest on that difference computed under § 218.302.
(ii) If the royalties you previously paid are more than the fees due under this section, then you are entitled to a refund or credit from MMS of 50 percent of the overpaid royalties. You are also entitled to a refund or credit of any interest that you paid on the overpaid royalties.
(c) For geothermal resources other than hot water, MMS will determine fees on a case-by-case basis.
§ 206.357
How do I calculate royalty due on byproducts?
(a) If you sell byproducts, you must determine the royalty due on the byproducts that are royalty-bearing under:
(1) Applicable lease terms of Class I leases and of Class III leases that do not elect to be subject to all of the BLM regulations promulgated for leases issued after August 8, 2005, under 43 CFR 3200.7(a)(2), or
(2) Applicable statutory provisions at 30 U.S.C. 1004(a)(2) for Class II leases and for Class III leases that do elect to be subject to all of the BLM regulations promulgated for leases issued after August 8, 2005, under 43 CFR 3200.7(a)(2).
(b) You must determine the royalty due on the byproducts by multiplying the royalty rate in your lease or that BLM prescribes under 43 CFR 3211.19 by a value of the byproducts determined in accordance with the first applicable of the following subparagraphs:
(1) The gross proceeds accruing to you from the arm's-length sale of the byproducts, less any applicable byproduct transportation allowances determined under §§ 206.358 and 206.359. See § 206.361 for additional provisions applicable to determining gross proceeds;
(2) Other relevant matters including, but not limited to, published or publicly available spot-market prices, or information submitted by the lessee concerning circumstances unique to a particular lease operation or the saleability of certain byproducts; or
(3) Any other reasonable valuation method approved by MMS.
§ 206.358
What are byproduct transportation allowances?
(a) When you determine the value of byproducts at a point off the geothermal lease, unit, or participating area, you are allowed a deduction in determining value, for royalty purposes, for your reasonable, actual costs incurred to:
(1) Transport the byproducts from a Federal lease, unit, or participating area to a sales point or point of delivery that is off the lease, unit, or participating area; or
(2) Transport the byproducts from a Federal lease, unit, or participating area, or from a geothermal use facility to a byproduct recovery facility when that byproduct recovery facility is off the lease, unit, or participating area and, if applicable, from the recovery facility to a sales point or point of delivery off the lease, unit, or participating area.
(b) Costs for transporting geothermal fluids from the lease to the geothermal use facility, whether on or off the lease, are not includible in the byproduct transportation allowance.
(c)(1) When you transport byproducts from a lease, unit, participating area, or geothermal use facility to a byproduct recovery facility, you are not required to allocate transportation costs between the quantity of marketable byproducts and the rejected waste material. The byproduct transportation allowance is authorized for the total production that is transported. You must express byproduct transportation allowances as a cost per unit of marketable byproducts transported.
(2) For byproducts that are extracted on the lease, unit, participating area, or at the geothermal use facility, the byproduct transportation allowance is authorized for the total byproduct that is transported to a point of sale off the lease, unit, or participating area. You must express byproduct transportation allowances as a cost per unit of byproduct transported.
(3) You may deduct transportation costs only when you sell, deliver, or otherwise utilize the transported byproduct and report and pay royalties on the byproduct.
(d) Reporting requirements. (1) You must use a discrete field on Form MMS-2014 to notify MMS of a transportation allowance.
(2) In conducting reviews and audits, MMS may require you to submit arm's-length transportation contracts, production agreements, operating agreements, and related documents. You must comply with any such requirements within the time MMS specifies. Recordkeeping requirements are found at part 212 of this chapter.
(e) Byproduct transportation allowances are subject to monitoring, review, and audit. If, after a review or audit, MMS determines that you have improperly determined a byproduct transportation allowance, you must pay any additional royalties due (plus interest computed under § 218.302). You are entitled to a credit for or refund of any overpaid royalties.
(f) If you commingled byproducts produced from Federal and non-Federal leases for transportation, you may not disproportionately allocate transportation costs to Federal lease production.
§ 206.359
How do I determine byproduct transportation allowances?
(a) For transportation costs you incur under an arm's-length contract, the transportation allowance will be the reasonable, actual costs you incurred for transporting the byproducts under that contract.
(1) In conducting reviews and audits, MMS will examine whether the contract reflects more than the consideration actually transferred either directly or indirectly from you to the transporter for the transportation. If the contract reflects more than the total consideration you paid, MMS may require you to determine the byproduct transportation allowance under paragraph (b) of this section.
(2) If MMS determines that the consideration you paid under an arm's-length byproduct transportation contract does not reflect the reasonable value of the transportation because of misconduct by or between the contracting parties, or because you otherwise have breached your duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, MMS will require you to determine the byproduct transportation allowance under paragraph (b) of this section. When MMS determines that the value of the transportation may be unreasonable, MMS will notify you and give you an opportunity to provide written information justifying your transportation costs.
(3) Where your payments for transportation under an arm's-length contract are not established on a dollars-per-unit basis, you must convert whatever consideration you paid to a dollar value equivalent for the purposes of this section.
(b) If you transport the byproduct yourself or under a non-arm's-length transportation arrangement, the byproduct transportation allowance is your reasonable actual costs for transportation during the reporting period, including:
(1) Operating and maintenance expenses under paragraphs (d) and (e) of this section;
(2) Overhead under paragraph (f) of this section; and either
(3) Depreciation under paragraphs (g) and (h) of this section and a return on undepreciated capital investment under paragraphs (g) and (i) of this section; or
(4) A return on capital investment in the transportation system under paragraphs (g) and (j) of this section.
(c)(1) Allowable capital costs under paragraph (b) of this section are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) that are an integral part of the transportation system.
(2)(i) You may include a return on capital you invested in the purchase of real estate to locate the byproduct transportation facilities if:
(A) The purchase is necessary; and
(B) The surface is not part of a Federal lease.
(ii) The rate of return will be the same rate determined in paragraph (k) of this section.
(3) You may not deduct the costs of gathering systems and other production-related facilities.
(d) Allowable operating expenses include:
(1) Operations supervision and engineering;
(2) Operations labor;
(3) Fuel;
(4) Utilities;
(5) Materials;
(6) Ad valorem property taxes;
(7) Rent;
(8) Supplies; and
(9) Any other directly allocable and attributable operating expense that you can document.
(e) Allowable maintenance expenses include:
(1) Maintenance of the transportation system;
(2) Maintenance of equipment;
(3) Maintenance labor; and
(4) Other directly allocable and attributable maintenance expenses that you can document.
(f) Overhead directly attributable and allocable to the operation and maintenance of the transportation system is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses.
(g) To compute costs associated with capital investment, a lessee may use either paragraphs (h) and (i) or paragraph (j) of this section. After a lessee has elected to use either method for a transportation system, the lessee may not later elect to change to the other alternative without MMS approval.
(h)(1) To compute depreciation, you must use a straight-line depreciation method based on either the life of the equipment or the life of the geothermal project which the transportation system services. After you choose the basis for depreciation, you may not change that basis without MMS approval. You may not depreciate equipment below a reasonable salvage value.
(2) A change in ownership of a transportation system does not alter the depreciation schedule established by the original lessee-owner for purposes of computing transportation costs.
(3) With or without a change in ownership, you may depreciate a transportation system only once.
(i) To calculate a return on undepreciated capital investment, multiply the remaining undepreciated capital balance as of the beginning of the period for which you are calculating the transportation allowance by the rate of return provided in paragraph (k) of this section.
(j) To compute a return on capital investment in the transportation system, the allowed cost will be the amount equal to the allowable capital investment in the transportation system multiplied by the rate of return determined pursuant to paragraph (k) of this section. There is no allowance for depreciation.
(k) The rate of return must be the industrial rate associated with Standard & Poor's BBB rating. The BBB rate must be the monthly average rate as published in Standard & Poor's Bond Guide for the first month for which the allowance is applicable. You must redetermine the rate at the beginning of each subsequent calendar year.
(l)(1) For new transportation facilities or arrangements, base your initial deduction on estimates of allowable byproduct transportation costs for the applicable period. Use the most recently available operations data for the transportation system or, if such data are not available, use estimates based on data for similar transportation systems.
(2) When actual cost information is available, you must amend your prior Form MMS-2014 reports to reflect actual byproduct transportation cost deductions for each month for which you reported and paid based on estimated byproduct transportation costs. You must pay any additional royalties due (together with interest computed under § 218.302). You are entitled to a credit for or a refund of any overpaid royalties.
§ 206.360
What records must I keep to support my calculations of royalty or fees under this subpart?
If you determine royalties or direct use fees for your geothermal resource under this subpart, you must retain all data relevant to the determination of the royalty value or the fee you paid. Recordkeeping requirements are found at part 212 of this chapter.
(a) You must be able to show:
(1) How you calculated the royalty value or fee you reported, including all allowable deductions; and
(2) How you complied with this subpart.
(b) Upon request, you must submit all data to MMS. You must comply with any such requirement within the time MMS specifies.
§ 206.361
How will MMS determine whether my royalty or direct use fee payments are correct?
(a)(1) The royalties or direct use fees that you report are subject to monitoring, review, and audit. The MMS may review and audit your data, and MMS will direct you to use a different measure of royalty value, gross proceeds, or fee, whichever is applicable, if it determines that the reported value, gross proceeds, or fee is inconsistent with the requirements of this subpart.
(2) If MMS directs you to use a different royalty value, measure of gross proceeds, or fee, you must either pay any royalties or fees due (together with interest computed under § 218.302) or report a credit for or request a refund of any overpaid royalties or fees.
(b) When the provisions in this subpart refer to gross proceeds either for the sale of electricity or the sale of a geothermal resource, in conducting reviews and audits MMS will examine whether your sales contract reflects the total consideration actually transferred, either directly or indirectly, from the buyer to you for the geothermal resource or electricity. If MMS determines that a contract does not reflect the total consideration, or the gross proceeds accruing to you under a contract do not reflect reasonable consideration because of misconduct by or between the contracting parties, or because you otherwise have breached your duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, MMS may require you to increase the gross proceeds to reflect any additional consideration. Alternatively, for Class I leases, MMS may require you to use another valuation method in the regulations applicable to dispositions other than under an arm's-length contract. The MMS will notify you to give you an opportunity to provide written information justifying your gross proceeds.
(c) For arm's-length sales, you have the burden of demonstrating that your contract is arm's length.
(d) The MMS may require you to certify that the provisions in your sales contract include all of the consideration the buyer paid you, either directly or indirectly, for the electricity or geothermal resource.
(e) Notwithstanding any other provision of this subpart, under no circumstances will the value of production for royalty purposes under a Class I lease where the geothermal resources are sold before use be less than the gross proceeds accruing to you.
(f) Gross proceeds for the sale of electricity or for the sale of the geothermal resource will be based on the highest price a prudent lessee can receive through legally enforceable claims under its contract.
(1) Absent contract revision or amendment, if you fail to take proper or timely action to receive prices or benefits to which you are entitled, you must pay royalty based upon that obtainable price or benefit.
(2) Contract revisions or amendments you make must be in writing and signed by all parties to the contract.
(3) If you make timely application for a price increase or benefit allowed under your contract, but the purchaser refuses and you take reasonable measures, which are documented, to force purchaser compliance, you will owe no additional royalties unless or until you receive additional monies or consideration resulting from the price increase. This paragraph (f)(3) will not be construed to permit you to avoid your royalty payment obligation in situations where a purchaser fails to pay, in whole or in part or timely, for a quantity of geothermal resources or electricity.
§ 206.362
What are my responsibilities to place production into marketable condition and to market production?
You must place geothermal resources and byproducts in marketable condition and market the geothermal resources or byproducts for the mutual benefit of the lessee and the lessor at no cost to the Federal Government. If you use gross proceeds under an arm's-length contract in determining royalty, you must increase those gross proceeds to the extent that the purchaser, or any other person, provides certain services that the seller normally would be responsible to perform to place the geothermal resources or byproducts in marketable condition or to market the geothermal resources or byproducts.
§ 206.363
When is an MMS audit, review, reconciliation, monitoring, or other like process considered final?
Notwithstanding any provision in these regulations to the contrary, no audit, review, reconciliation, monitoring, or other like process that results in a redetermination by MMS of royalty or fees due under this subpart is considered final or binding as against the Federal Government or its beneficiaries until MMS formally closes the audit period in writing.
§ 206.364
How do I request a value or gross proceeds determination?
(a) You may request a value determination from MMS regarding any geothermal resources produced from a Class I lease or for byproducts produced from a Class I, Class II, or Class III lease. You may also request a gross proceeds determination for a Class II or Class III lease. Your request must:
(1) Be in writing;
(2) Identify specifically all leases involved, all owners of interests in those leases, and the operator(s) for those leases;
(3) Completely explain all relevant facts. You must inform MMS of any changes to relevant facts that occur before we respond to your request;
(4) Include copies of all relevant documents;
(5) Provide your analysis of the issue(s), including citations to all relevant precedents (including adverse precedents); and
(6) Suggest your proposed gross proceeds calculation or valuation method.
(b) In response to your request:
(1) The Assistant Secretary, Land and Minerals Management, may issue a determination; or
(2) The MMS may issue a determination; or
(3) The MMS may inform you in writing that MMS will not provide a determination. Situations in which MMS typically will not provide any determination include, but are not limited to:
(i) Requests for guidance on hypothetical situations; and
(ii) Matters that are the subject of pending litigation or administrative appeals.
(c)(1) A determination signed by the Assistant Secretary, Land and Minerals Management, is binding on both you and MMS until the Assistant Secretary modifies or rescinds it.
(2) After the Assistant Secretary issues a determination, you must make any adjustments in royalty payments that follow from the determination and, if you owe additional royalties, pay the royalties owed together with late payment interest computed under § 218.302.
(3) A determination signed by the Assistant Secretary is the final action of the Department and is subject to judicial review under 5 U.S.C. 701-706.
(d) A determination issued by MMS is binding on MMS and delegated States, but not on you, with respect to the specific situation addressed in the determination unless the MMS (for MMS-issued determinations) or the Assistant Secretary modifies or rescinds it.
(1) A determination by MMS is not an appealable decision or order under 30 CFR part 290 subpart B.
(2) If you receive an order requiring you to pay royalty on the same basis as the determination, you may appeal that order under 30 CFR part 290 subpart B.
(e) In making a determination, MMS or the Assistant Secretary may use any of the applicable criteria in this subpart.
(f) A change in an applicable statute or regulation on which any determination is based takes precedence over the determination after the effective date of the statute or regulation, regardless of whether the MMS or the Assistant Secretary modifies or rescinds the determination.
(g) The MMS or the Assistant Secretary generally will not retroactively modify or rescind a determination issued under paragraph (d) of this section, unless:
(1) There was a misstatement or omission of material facts; or
(2) The facts subsequently developed are materially different from the facts on which the guidance was based.
(h) The MMS may make requests and replies under this section available to the public, subject to the confidentiality requirements under § 206.365.
§ 206.365
Does MMS protect information I provide?
Certain information you submit to MMS regarding royalties or fees on geothermal resources or byproducts, including deductions and allowances, may be exempt from disclosure. To the extent applicable laws and regulations permit, MMS will keep confidential any data you submit that is privileged, confidential, or otherwise exempt from disclosure. All requests for information must be submitted under the Freedom of Information Act regulations of the Department of the Interior at 43 CFR part 2.
§ 206.366
What is the nominal fee that a State, tribal, or local government lessee must pay for the use of geothermal resources?
If a State, tribal, or local government lessee uses a geothermal resource without sale and for public purposes—other than commercial production or generation of electricity—the State, tribal, or local government lessee must pay a nominal fee. A nominal fee means a slight or de minimis fee. The MMS will determine the fee on a case-by-case basis.
Subpart I—OCS Sulfur [Reserved]

Subpart J—Indian Coal

Source:
61 FR 5481, Feb. 12, 1996, unless otherwise noted.
§ 206.450
Purpose and scope.
(a) This subpart prescribes the procedures to establish the value, for royalty purposes, of all coal from Indian Tribal and allotted leases (except leases on the Osage Indian Reservation, Osage County, Oklahoma).
(b) If the specific provisions of any statute, treaty, or settlement agreement between the Indian lessor and a lessee resulting from administrative or judicial litigation, or any coal lease subject to the requirements of this subpart, are inconsistent with any regulation in this subpart, then the statute, treaty, lease provision, or settlement shall govern to the extent of that inconsistency.
(c) All royalty payments are subject to later audit and adjustment.
(d) The regulations in this subpart are intended to ensure that the trust responsibilities of the United States with respect to the administration of Indian coal leases are discharged in accordance with the requirements of the governing mineral leasing laws, treaties, and lease terms.
§ 206.451
Definitions.
Ad valorem lease means a lease where the royalty due to the lessor is based upon a percentage of the amount or value of the coal.
Allowance means an approved, or an MMS-initially accepted deduction in determining value for royalty purposes. Coal washing allowance means an allowance for the reasonable, actual costs incurred by the lessee for coal washing, or an approved or MMS-initially accepted deduction for the costs of washing coal, determined pursuant to this subpart. Transportation allowance means an allowance for the reasonable, actual costs incurred by the lessee for moving coal to a point of sale or point of delivery remote from both the lease and mine or wash plant, or an approved MMS-initially accepted deduction for costs of such transportation, determined pursuant to this subpart.
Area means a geographic region in which coal has similar quality and economic characteristics. Area boundaries are not officially designated and the areas are not necessarily named.
Arm's-length contract means a contract or agreement that has been arrived at in the marketplace between independent, nonaffiliated persons with opposing economic interests regarding that contract. For purposes of this subpart, two persons are affiliated if one person controls, is controlled by, or is under common control with another person. For purposes of this subpart, based on the instruments of ownership of the voting securities of an entity, or based on other forms of ownership: ownership in excess of 50 percent constitutes control; ownership of 10 through 50 percent creates a presumption of control; and ownership of less than 10 percent creates a presumption of noncontrol which MMS may rebut if it demonstrates actual or legal control, including the existence of interlocking directorates. Notwithstanding any other provisions of this subpart, contracts between relatives, either by blood or by marriage, are not arm's-length contracts. MMS may require the lessee to certify ownership control. To be considered arm's-length for any production month, a contract must meet the requirements of this definition for that production month, as well as when the contract was executed.
Audit means a review, conducted in accordance with generally accepted accounting and auditing standards, of royalty payment compliance activities of lessees or other interest holders who pay royalties, rents, or bonuses on Indian leases.
BIA means the Bureau of Indian Affairs of the Department of the Interior.
BLM means the Bureau of Land Management of the Department of the Interior.
Coal means coal of all ranks from lignite through anthracite.
Coal washing means any treatment to remove impurities from coal. Coal washing may include, but is not limited to, operations such as flotation, air, water, or heavy media separation; drying; and related handling (or combination thereof).
Contract means any oral or written agreement, including amendments or revisions thereto, between two or more persons and enforceable by law that with due consideration creates an obligation.
Gross proceeds (for royalty payment purposes) means the total monies and other consideration accruing to a coal lessee for the production and disposition of the coal produced. Gross proceeds includes, but is not limited to, payments to the lessee for certain services such as crushing, sizing, screening, storing, mixing, loading, treatment with substances including chemicals or oils, and other preparation of the coal to the extent that the lessee is obligated to perform them at no cost to the Indian lessor. Gross proceeds, as applied to coal, also includes but is not limited to reimbursements for royalties, taxes or fees, and other reimbursements. Tax reimbursements are part of the gross proceeds accruing to a lessee even though the Indian royalty interest may be exempt from taxation. Monies and other consideration, including the forms of consideration identified in this paragraph, to which a lessee is contractually or legally entitled but which it does not seek to collect through reasonable efforts are also part of gross proceeds.
Indian allottee means any Indian for whom land or an interest in land is held in trust by the United States or who holds title subject to Federal restriction against alienation.
Indian Tribe means any Indian Tribe, band, nation, pueblo, community, rancheria, colony, or other group of Indians for which any land or interest in land is held in trust by the United States or which is subject to Federal restriction against alienation.
Lease means any contract, profit-share arrangement, joint venture, or other agreement issued or approved by the United States for an Indian coal resource under a mineral leasing law that authorizes exploration for, development or extraction of, or removal of coal—or the land covered by that authorization, whichever is required by the context.
Lessee means any person to whom the Indian Tribe or an Indian allottee issues a lease, and any person who has been assigned an obligation to make royalty or other payments required by the lease. This includes any person who has an interest in a lease as well as an operator or payor who has no interest in the lease but who has assumed the royalty payment responsibility.
Like-quality coal means coal that has similar chemical and physical characteristics.
Marketable condition means coal that is sufficiently free from impurities and otherwise in a condition that it will be accepted by a purchaser under a sales contract typical for that area.
Mine means an underground or surface excavation or series of excavations and the surface or underground support facilities that contribute directly or indirectly to mining, production, preparation, and handling of lease products.
MMS means the Minerals Management Service of the Department of the Interior.
Net-back method means a method for calculating market value of coal at the lease or mine. Under this method, costs of transportation, washing, handling, etc., are deducted from the ultimate proceeds received for the coal at the first point at which reasonable values for the coal may be determined by a sale pursuant to an arm's-length contract or by comparison to other sales of coal, to ascertain value at the mine.
Net output means the quantity of washed coal that a washing plant produces.
Person means by individual, firm, corporation, association, partnership, consortium, or joint venture.
Sales type code means the contract type or general disposition (e.g., arm's-length or non-arm's-length) of production from the lease. The sales type code applies to the sales contract, or other disposition, and not to the arm's-length or non-arm's-length nature of a transportation or washing allowance.
Spot market price means the price received under any sales transaction when planned or actual deliveries span a short period of time, usually not exceeding one year.
[61 FR 5481, Feb. 12, 1996, as amended at 64 FR 43289, Aug. 10, 1999; 73 FR 15891, Mar. 26, 2008]
§ 206.452
Coal subject to royalties—general provisions.
(a) All coal (except coal unavoidably lost as determined by BLM pursuant to 43 CFR group 3400) from an Indian lease subject to this part is subject to royalty. This includes coal used, sold, or otherwise disposed of by the lessee on or off the lease.
(b) If a lessee receives compensation for unavoidably lost coal through insurance coverage or other arrangements, royalties at the rate specified in the lease are to be paid on the amount of compensation received for the coal. No royalty is due on insurance compensation received by the lessee for other losses.
(c) If waste piles or slurry ponds are reworked to recover coal, the lessee shall pay royalty at the rate specified in the lease at the time the recovered coal is used, sold, or otherwise finally disposed of. The royalty rate shall be that rate applicable to the production method used to initially mine coal in the waste pile or slurry pond; i.e., underground mining method or surface mining method. Coal in waste pits or slurry ponds initially mined from Indian leases shall be allocated to such leases regardless of whether it is stored on Indian lands. The lessee shall maintain accurate records to determine to which individual Indian lease coal in the waste pit or slurry pond should be allocated. However, nothing in this section requires payment of a royalty on coal for which a royalty has already been paid.
§ 206.453
Quality and quantity measurement standards for reporting and paying royalties.
For all leases subject to this subpart, the quantity of coal on which royalty is due shall be measured in short tons (of 2,000 pounds each) by methods prescribed by the BLM. Coal quantity information will be reported on appropriate forms required under 30 CFR part 210—Forms and Reports.
[61 FR 5481, Feb. 12, 1996, as amended at 66 FR 45769, Aug. 30, 2001; 73 FR 15892, Mar. 26, 2008]
§ 206.454
Point of royalty determination.
(a) For all leases subject to this subpart, royalty shall be computed on the basis of the quantity and quality of Indian coal in marketable condition measured at the point of royalty measurement as determined jointly by BLM and MMS.
(b) Coal produced and added to stockpiles or inventory does not require payment of royalty until such coal is later used, sold, or otherwise finally disposed of. MMS may ask BLM or BIA to increase the lease bond to protect the lessor's interest when BLM determines that stockpiles or inventory become excessive so as to increase the risk of degradation of the resource.
(c) The lessee shall pay royalty at a rate specified in the lease at the time the coal is used, sold, or otherwise finally disposed of, unless otherwise provided for at § 206.455(d) of this subpart.
§ 206.455
Valuation standards for cents-per-ton leases.
(a) This section is applicable to coal leases on Indian Tribal and allotted Indian lands (except leases on the Osage Indian Reservation, Osage County, Oklahoma) which provide for the determination of royalty on a cents-per-ton (or other quantity) basis.
(b) The royalty for coal from leases subject to this section shall be based on the dollar rate per ton prescribed in the lease. That dollar rate shall be applicable to the actual quantity of coal used, sold, or otherwise finally disposed of, including coal which is avoidably lost as determined by BLM pursuant to 43 CFR part 3400.
(c) For leases subject to this section, there shall be no allowances for transportation, removal of impurities, coal washing, or any other processing or preparation of the coal.
(d) When a coal lease is readjusted pursuant to 43 CFR part 3400 and the royalty valuation method changes from a cents-per-ton basis to an ad valorem basis, coal which is produced prior to the effective date of readjustment and sold or used within 30 days of the effective date of readjustment shall be valued pursuant to this section. All coal that is not used, sold, or otherwise finally disposed of within 30 days after the effective date of readjustment shall be valued pursuant to the provisions of § 206.456 of this subpart, and royalties shall be paid at the royalty rate specified in the readjusted lease.
§ 206.456
Valuation standards for ad valorem leases.
(a) This section is applicable to coal leases on Indian Tribal and allotted Indian lands (except leases on the Osage Indian Reservation, Osage County, Oklahoma) which provide for the determination of royalty as a percentage of the amount of value of coal (ad valorem). The value for royalty purposes of coal from such leases shall be the value of coal determined pursuant to this section, less applicable coal washing allowances and transportation allowances determined pursuant to §§ 206.457 through 206.461 of this subpart, or any allowance authorized by § 206.464 of this subpart. The royalty due shall be equal to the value for royalty purposes multiplied by the royalty rate in the lease.
(b)(1) The value of coal that is sold pursuant to an arm's-length contract shall be the gross proceeds accruing to the lessee, except as provided in paragraphs (b)(2), (b)(3), and (b)(5) of this section. The lessee shall have the burden of demonstrating that its contract is arm's-length. The value which the lessee reports, for royalty purposes, is subject to monitoring, review, and audit.
(2) In conducting reviews and audits, MMS will examine whether the contract reflects the total consideration actually transferred either directly or indirectly from the buyer to the seller for the coal produced. If the contract does not reflect the total consideration, then MMS may require that the coal sold pursuant to that contract be valued in accordance with paragraph (c) of this section. Value may not be based on less than the gross proceeds accruing to the lessee for the coal production, including the additional consideration.
(3) If MMS determines that the gross proceeds accruing to the lessee pursuant to an arm's-length contract do not reflect the reasonable value of the production because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then MMS shall require that the coal production be valued pursuant to paragraphs (c)(2)(ii), (c)(2)(iii), (c)(2)(iv), or (c)(2)(v) of this section, and in accordance with the notification requirements of paragraph (d)(3) of this section. When MMS determines that the value may be unreasonable, MMS will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's reported coal value.
(4) MMS may require a lessee to certify that its arm's-length contract provisions include all of the consideration to be paid by the buyer, either directly or indirectly, for the coal production.
(5) The value of production for royalty purposes shall not include payments received by the lessee pursuant to a contract which the lessee demonstrates, to MMS' satisfaction, were not part of the total consideration paid for the purchase of coal production.
(c)(1) The value of coal from leases subject to this section and which is not sold pursuant to an arm's-length contract shall be determined in accordance with this section.
(2) If the value of the coal cannot be determined pursuant to paragraph (b) of this section, then the value shall be determined through application of other valuation criteria. The criteria shall be considered in the following order, and the value shall be based upon the first applicable criterion:
(i) The gross proceeds accruing to the lessee pursuant to a sale under its non-arm's-length contract (or other disposition of produced coal by other than an arm's-length contract), provided that those gross proceeds are within the range of the gross proceeds derived from, or paid under, comparable arm's-length contracts between buyers and sellers neither of whom is affiliated with the lessee for sales, purchases, or other dispositions of like-quality coal produced in the area. In evaluating the comparability of arm's-length contracts for the purposes of these regulations, the following factors shall be considered: price, time of execution, duration, market or markets served, terms, quality of coal, quantity, and such other factors as may be appropriate to reflect the value of the coal;
(ii) Prices reported for that coal to a public utility commission;
(iii) Prices reported for that coal to the Energy Information Administration of the Department of Energy;
(iv) Other relevant matters including, but not limited to, published or publicly available spot market prices, or information submitted by the lessee concerning circumstances unique to a particular lease operation or the salability of certain types of coal;
(v) If a reasonable value cannot be determined using paragraphs (c)(2)(i), (c)(2)(ii), (c)(2)(iii), or (c)(2)(iv) of this section, then a net-back method or any other reasonable method shall be used to determine value.
(3) When the value of coal is determined pursuant to paragraph (c)(2) of this section, that value determination shall be consistent with the provisions contained in paragraph (b)(5) of this section.
(d)(1) Where the value is determined pursuant to paragraph (c) of this section, that value does not require MMS' prior approval. However, the lessee shall retain all data relevant to the determination of royalty value. Such data shall be subject to review and audit, and MMS will direct a lessee to use a different value if it determines that the reported value is inconsistent with the requirements of these regulations.
(2) An Indian lessee will make available upon request to the authorized MMS or Indian representatives, or to the Inspector General of the Department of the Interior or other persons authorized to receive such information, arm's-length sales and sales quantity data for like-quality coal sold, purchased, or otherwise obtained by the lessee from the area.
(3) A lessee shall notify MMS if it has determined value pursuant to paragraphs (c)(2)(ii), (c)(2)(iii), (c)(2)(iv), or (c)(2)(v) of this section. The notification shall be by letter to the Associate Director for Minerals Revenue Management or his/her designee. The letter shall identify the valuation method to be used and contain a brief description of the procedure to be followed. The notification required by this section is a one-time notification due no later than the month the lessee first reports royalties on the Form MMS-4430 using a valuation method authorized by paragraphs (c)(2)(ii), (c)(2)(iii), (c)(2)(iv), or (c)(2)(v) of this section, and each time there is a change in a method under paragraphs (c)(2)(iv) or (c)(2)(v) of this section.
(e) If MMS determines that a lessee has not properly determined value, the lessee shall be liable for the difference, if any, between royalty payments made based upon the value it has used and the royalty payments that are due based upon the value established by MMS. The lessee shall also be liable for interest computed pursuant to 30 CFR 218.202. If the lessee is entitled to a credit, MMS will provide instructions for the taking of that credit.
(f) The lessee may request a value determination from MMS. In that event, the lessee shall propose to MMS a value determination method, and may use that method in determining value for royalty purposes until MMS issues its decision. The lessee shall submit all available data relevant to its proposal. MMS shall expeditiously determine the value based upon the lessee's proposal and any additional information MMS deems necessary. That determination shall remain effective for the period stated therein. After MMS issues its determination, the lessee shall make the adjustments in accordance with paragraph (e) of this section.
(g) Notwithstanding any other provisions of this section, under no circumstances shall the value for royalty purposes be less than the gross proceeds accruing to the lessee for the disposition of produced coal less applicable provisions of paragraph (b)(5) of this section and less applicable allowances determined pursuant to §§ 206.457 through 206.461 and § 206.464 of this subpart.
(h) The lessee is required to place coal in marketable condition at no cost to the Indian lessor. Where the value established pursuant to this section is determined by a lessee's gross proceeds, that value shall be increased to the extent that the gross proceeds has been reduced because the purchaser, or any other person, is providing certain services, the cost of which ordinarily is the responsibility of the lessee to place the coal in marketable condition.
(i) Value shall be based on the highest price a prudent lessee can receive through legally enforceable claims under its contract. Absent contract revision or amendment, if the lessee fails to take proper or timely action to receive prices or benefits to which it is entitled, it must pay royalty at a value based upon that obtainable price or benefit. Contract revisions or amendments shall be in writing and signed by all parties to an arm's-length contract, and may be retroactively applied to value for royalty purposes for a period not to exceed two years, unless MMS approves a longer period. If the lessee makes timely application for a price increase allowed under its contract but the purchaser refuses, and the lessee takes reasonable measures, which are documented, to force purchaser compliance, the lessee will owe no additional royalties unless or until monies or consideration resulting from the price increase are received. This paragraph shall not be construed to permit a lessee to avoid its royalty payment obligation in situations where a purchaser fails to pay, in whole or in part or timely, for a quantity of coal.
(j) Notwithstanding any provision in these regulations to the contrary, no review, reconciliation, monitoring, or other like process that results in a redetermination by MMS of value under this section shall be considered final or binding as against the Indian Tribes or allottees until the audit period is formally closed.
(k) Certain information submitted to MMS to support valuation proposals, including transportation, coal washing, or other allowances pursuant to §§ 206.457 through 206.461 and § 206.464 of this subpart, is exempted from disclosure by the Freedom of Information Act, 5 U.S.C. 522. Any data specified by the Act to be privileged, confidential, or otherwise exempt shall be maintained in a confidential manner in accordance with applicable law and regulations. All requests for information about determinations made under this part are to be submitted in accordance with the Freedom of Information Act regulation of the Department of the Interior, 43 CFR part 2. Nothing in this section is intended to limit or diminish in any manner whatsoever the right of an Indian lessor to obtain any and all information as such lessor may be lawfully entitled from MMS or such lessor's lessee directly under the terms of the lease or applicable law.
[61 FR 5481, Feb. 12, 1996, as amended at 66 FR 45769, Aug. 30, 2001]
§ 206.457
Washing allowances—general.
(a) For ad valorem leases subject to § 206.456 of this subpart, MMS shall, as authorized by this section, allow a deduction in determining value for royalty purposes for the reasonable, actual costs incurred to wash coal, unless the value determined pursuant to § 206.456 of this subpart was based upon like-quality unwashed coal. Under no circumstances will the authorized washing allowance and the transportation allowance reduce the value for royalty purposes to zero.
(b) If MMS determines that a lessee has improperly determined a washing allowance authorized by this section, then the lessee shall be liable for any additional royalties, plus interest determined in accordance with 30 CFR 218.202, or shall be entitled to a credit, without interest.
(c) Lessees shall not disproportionately allocate washing costs to Indian leases.
(d) No cost normally associated with mining operations and which are necessary for placing coal in marketable condition shall be allowed as a cost of washing.
(e) Coal washing costs shall only be recognized as allowances when the washed coal is sold and royalties are reported and paid.
[61 FR 5481, Feb. 12, 1996, as amended at 64 FR 43289, Aug. 10, 1999]
§ 206.458
Determination of washing allowances.
(a) Arm's-length contracts. (1) For washing costs incurred by a lessee pursuant to an arm's-length contract, the washing allowance shall be the reasonable actual costs incurred by the lessee for washing the coal under that contract, subject to monitoring, review, audit, and possible future adjustment. MMS' prior approval is not required before a lessee may deduct costs incurred under an arm's-length contract. However, before any deduction may be taken, the lessee must submit a completed page one of Form MMS-4292, Coal Washing Allowance Report, in accordance with paragraph (c)(1) of this section. A washing allowance may be claimed retroactively for a period of not more than 3 months prior to the first day of the month that Form MMS-4292 is filed with MMS, unless MMS approves a longer period upon a showing of good cause by the lessee.
(2) In conducting reviews and audits, MMS will examine whether the contract reflects more than the consideration actually transferred either directly or indirectly from the lessee to the washer for the washing. If the contract reflects more than the total consideration paid, then MMS may require that the washing allowance be determined in accordance with paragraph (b) of this section.
(3) If MMS determines that the consideration paid pursuant to an arm's-length washing contract does not reflect the reasonable value of the washing because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then MMS shall require that the washing allowance be determined in accordance with paragraph (b) of this section. When MMS determines that the value of the washing may be unreasonable, MMS will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's washing costs.
(4) Where the lessee's payments for washing under an arm's-length contract are not based on a dollar-per-unit basis, the lessee shall convert whatever consideration is paid to a dollar value equivalent. Washing allowances shall be expressed as a cost per ton of coal washed.
(b) Non-arm's-length or no contract. (1) If a lessee has a non-arm's-length contract or has no contract, including those situations where the lessee performs washing for itself, the washing allowance will be based upon the lessee's reasonable actual costs. All washing allowances deducted under a non-arm's-length or no contract situation are subject to monitoring, review, audit, and possible future adjustment. Prior MMS approval of washing allowances is not required for non-arm's-length or no contract situations. However, before any estimated or actual deduction may be taken, the lessee must submit a completed Form MMS-4292 in accordance with paragraph (c)(2) of this section. A washing allowance may be claimed retroactively for a period of not more than 3 months prior to the first day of the month that Form MMS-4292 is filed with MMS, unless MMS approves a longer period upon a showing of good cause by the lessee. MMS will monitor the allowance deduction to ensure that deductions are reasonable and allowable. When necessary or appropriate, MMS may direct a lessee to modify its actual washing allowance.
(2) The washing allowance for non-arm's-length or no contract situations shall be based upon the lessee's actual costs for washing during the reported period, including operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment in accordance with paragraph (b)(2)(iv)(A) of this section, or a cost equal to the depreciable investment in the wash plant multiplied by the rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) which are an integral part of the wash plant.
(i) Allowable operating expenses include: Operations supervision and engineering; operations labor; fuel; utilities; materials; ad valorem property taxes; rent; supplies; and any other directly allocable and attributable operating expense which the lessee can document.
(ii) Allowable maintenance expenses include: Maintenance of the wash plant; maintenance of equipment; maintenance labor; and other directly allocable and attributable maintenance expenses which the lessee can document.
(iii) Overhead attributable and allocable to the operation and maintenance of the wash plant is an allowable expense. State and Federal income taxes and severance taxes, including royalties, are not allowable expenses.
(iv) A lessee may use either paragraph (b)(2)(iv)(A) or (b)(2)(iv)(B) of this section. After a lessee has elected to use either method for a wash plant, the lessee may not later elect to change to the other alternative without approval of MMS.
(A) To compute depreciation, the lessee may elect to use either a straight-line depreciation method based on the life of equipment or on the life of the reserves which the wash plant services, whichever is appropriate, or a unit of production method. After an election is made, the lessee may not change methods without MMS approval. A change in ownership of a wash plant shall not alter the depreciation schedule established by the original operator/lessee for purposes of the allowance calculation. With or without a change in ownership, a wash plant shall be depreciated only once. Equipment shall not be depreciated below a reasonable salvage value.
(B) MMS shall allow as a cost an amount equal to the allowable capital investment in the wash plant multiplied by the rate of return determined pursuant to paragraph (b)(2)(v) of this section. No allowance shall be provided for depreciation. This alternative shall apply only to plants first placed in service or acquired after March 1, 1989.
(v) The rate of return shall be the industrial rate associated with Standard and Poor's BBB rating. The rate of return shall be the monthly average rate as published in Standard and Poor's Bond Guide for the first month of the reporting period for which the allowance is applicable and shall be effective during the reporting period. The rate shall be redetermined at the beginning of each subsequent washing allowance reporting period (which is determined pursuant to paragraph (c)(2) of this section).
(3) The washing allowance for coal shall be determined based on the lessee's reasonable and actual cost of washing the coal. The lessee may not take an allowance for the costs of washing lease production that is not royalty bearing.
(c) Reporting requirements—(1) Arm's-length contracts. (i) With the exception of those washing allowances specified in paragraphs (c)(1)(v) and (c)(1)(vi) of this section, the lessee shall submit page one of the initial Form MMS-4292 prior to, or at the same time, as the washing allowance determined pursuant to an arm's-length contract is reported on Form MMS-4430, Solid Minerals Production and Royalty Report. A Form MMS-4292 received by the end of the month that the Form MMS-4430 is due shall be considered to be received timely.
(ii) The initial Form MMS-4292 shall be effective for a reporting period beginning the month that the lessee is first authorized to deduct a washing allowance and shall continue until the end of the calendar year, or until the applicable contract or rate terminates or is modified or amended, whichever is earlier.
(iii) After the initial reporting period and for succeeding reporting periods, lessees must submit page one of Form MMS-4292 within 3 months after the end of the calendar year, or after the applicable contract or rate terminates or is modified or amended, whichever is earlier, unless MMS approves a longer period (during which period the lessee shall continue to use the allowance from the previous reporting period).
(iv) MMS may require that a lessee submit arm's-length washing contracts and related documents. Documents shall be submitted within a reasonable time, as determined by MMS.
(v) Washing allowances which are based on arm's-length contracts and which are in effect at the time these regulations become effective will be allowed to continue until such allowances terminate. For the purposes of this section, only those allowances that have been approved by MMS in writing shall qualify as being in effect at the time these regulations become effective.
(vi) MMS may establish, in appropriate circumstances, reporting requirements that are different from the requirements of this section.
(2) Non-arm's-length or no contract. (i) With the exception of those washing allowances specified in paragraphs (c)(2)(v) and (c)(2)(vii) of this section, the lessee shall submit an initial Form MMS-4292 prior to, or at the same time as, the washing allowance determined pursuant to a non-arm's-length contract or no contract situation is reported on Form MMS-4430, Solid Minerals Production and Royalty Report. A Form MMS-4292 received by the end of the month that the Form MMS-4430 is due shall be considered to be timely received. The initial reporting may be based on estimated costs.
(ii) The initial Form MMS-4292 shall be effective for a reporting period beginning the month that the lessee first is authorized to deduct a washing allowance and shall continue until the end of the calendar year, or until the washing under the non-arm's-length contract or the no contract situation terminates, whichever is earlier.
(iii) For calendar-year reporting periods succeeding the initial reporting period, the lessee shall submit a completed Form MMS-4292 containing the actual costs for the previous reporting period. If coal washing is continuing, the lessee shall include on Form MMS-4292 its estimated costs for the next calendar year. The estimated coal washing allowance shall be based on the actual costs for the previous period plus or minus any adjustments which are based on the lessee's knowledge of decreases or increases which will affect the allowance. Form MMS-4292 must be received by MMS within 3 months after the end of the previous reporting period, unless MMS approves a longer period (during which period the lessee shall continue to use the allowance from the previous reporting period).
(iv) For new wash plants, the lessee's initial Form MMS-4292 shall include estimates of the allowable coal washing costs for the applicable period. Cost estimates shall be based upon the most recently available operations data for the plant, or if such data are not available, the lessee shall use estimates based upon industry data for similar coal wash plants.
(v) Washing allowances based on non-arm's-length or no contract situations which are in effect at the time these regulations become effective will be allowed to continue until such allowances terminate. For the purposes of this section, only those allowances that have been approved by MMS in writing shall qualify as being in effect at the time these regulations become effective.
(vi) Upon request by MMS, the lessee shall submit all data used by the lessee to prepare its Forms MMS-4292. The data shall be provided within a reasonable period of time, as determined by MMS.
(vii) MMS may establish, in appropriate circumstances, reporting requirements which are different from the requirements of this section.
(3) MMS may establish coal washing allowance reporting dates for individual leases different from those specified in this subpart in order to provide more effective administration. Lessees will be notified of any change in their reporting period.
(4) Washing allowances must be reported as a separate line on the Form MMS-4430, unless MMS approves a different reporting procedure.
(d) Interest assessments for incorrect or late reports and failure to report. (1) If a lessee deducts a washing allowance on its Form MMS-4430 without complying with the requirements of this section, the lessee shall be liable for interest on the amount of such deduction until the requirements of this section are complied with. The lessee also shall repay the amount of any allowance which is disallowed by this section.
(2) If a lessee erroneously reports a washing allowance which results in an underpayment of royalties, interest shall be paid on the amount of that underpayment.
(3) Interest required to be paid by this section shall be determined in accordance with 30 CFR 218.202.
(e) Adjustments. (1) If the actual coal washing allowance is less than the amount the lessee has taken on Form MMS-4430 for each month during the allowance form reporting period, the lessee shall be required to pay additional royalties due plus interest computed pursuant to 30 CFR 218.202, retroactive to the first month the lessee is authorized to deduct a washing allowance. If the actual washing allowance is greater than the amount the lessee has estimated and taken during the reporting period, the lessee shall be entitled to a credit, without interest.
(2) The lessee must submit a corrected Form MMS-4430 to reflect actual costs, together with any payment, in accordance with instructions provided by MMS.
(f) Other washing cost determinations. The provisions of this section shall apply to determine washing costs when establishing value using a net-back valuation procedure or any other procedure that requires deduction of washing costs.
[61 FR 5481, Feb. 12, 1996, as amended at 66 FR 45769, Aug. 30, 2001]
§ 206.459
Allocation of washed coal.
(a) When coal is subjected to washing, the washed coal must be allocated to the leases from which it was extracted.
(b) When the net output of coal from a washing plant is derived from coal obtained from only one lease, the quantity of washed coal allocable to the lease will be based on the net output of the washing plant.
(c) When the net output of coal from a washing plant is derived from coal obtained from more than one lease, unless determined otherwise by BLM, the quantity of net output of washed coal allocable to each lease will be based on the ratio of measured quantities of coal delivered to the washing plant and washed from each lease compared to the total measured quantities of coal delivered to the washing plant and washed.
§ 206.460
Transportation allowances—general.
(a) For ad valorem leases subject to § 206.456 of this subpart, where the value for royalty purposes has been determined at a point remote from the lease or mine, MMS shall, as authorized by this section, allow a deduction in determining value for royalty purposes for the reasonable, actual costs incurred to:
(1) Transport the coal from an Indian lease to a sales point which is remote from both the lease and mine; or
(2) Transport the coal from an Indian lease to a wash plant when that plant is remote from both the lease and mine and, if applicable, from the wash plant to a remote sales point. In-mine transportation costs shall not be included in the transportation allowance.
(b) Under no circumstances will the authorized washing allowance and the transportation allowance reduce the value for royalty purposes to zero.
(c)(1) When coal transported from a mine to a wash plant is eligible for a transportation allowance in accordance with this section, the lessee is not required to allocate transportation costs between the quantity of clean coal output and the rejected waste material. The transportation allowance shall be authorized for the total production which is transported. Transportation allowances shall be expressed as a cost per ton of cleaned coal transported.
(2) For coal that is not washed at a wash plant, the transportation allowance shall be authorized for the total production which is transported. Transportation allowances shall be expressed as a cost per ton of coal transported.
(3) Transportation costs shall only be recognized as allowances when the transported coal is sold and royalties are reported and paid.
(d) If, after a review and/or audit, MMS determines that a lessee has improperly determined a transportation allowance authorized by this section, then the lessee shall pay any additional royalties, plus interest, determined in accordance with 30 CFR 218.202, or shall be entitled to a credit, without interest.
(e) Lessees shall not disproportionately allocate transportation costs to Indian leases.
[61 FR 5481, Feb. 12, 1996, as amended at 64 FR 43289, Aug. 10, 1999]
§ 206.461
Determination of transportation allowances.
(a) Arm's-length contracts. (1) For transportation costs incurred by a lessee pursuant to an arm's-length contract, the transportation allowance shall be the reasonable, actual costs incurred by the lessee for transporting the coal under that contract, subject to monitoring, review, audit, and possible future adjustment. MMS' prior approval is not required before a lessee may deduct costs incurred under an arm's-length contract. However, before any deduction may be taken, the lessee must submit a completed page one of Form MMS-4293, Coal Transportation Allowance Report, in accordance with paragraph (c)(1) of this section. A transportation allowance may be claimed retroactively for a period of not more than 3 months prior to the first day of the month that Form MMS-4293 is filed with MMS, unless MMS approves a longer period upon a showing of good cause by the lessee.
(2) In conducting reviews and audits, MMS will examine whether the contract reflects more than the consideration actually transferred either directly or indirectly from the lessee to the transporter for the transportation. If the contract reflects more than the total consideration paid, then MMS may require that the transportation allowance be determined in accordance with paragraph (b) of this section.
(3) If MMS determines that the consideration paid pursuant to an arm's-length transportation contract does not reflect the reasonable value of the transportation because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then MMS shall require that the transportation allowance be determined in accordance with paragraph (b) of this section. When MMS determines that the value of the transportation may be unreasonable, MMS will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's transportation costs.
(4) Where the lessee's payments for transportation under an arm's-length contract are not based on a dollar-per-unit basis, the lessee shall convert whatever consideration is paid to a dollar value equivalent for the purposes of this section.
(b) Non-arm's-length or no contract. (1) If a lessee has a non-arm's-length contract or has no contract, including those situations where the lessee performs transportation services for itself, the transportation allowance will be based upon the lessee's reasonable actual costs. All transportation allowances deducted under a non-arm's-length or no contract situation are subject to monitoring, review, audit, and possible future adjustment. Prior MMS approval of transportation allowances is not required for non-arm's-length or no contract situations. However, before any estimated or actual deduction may be taken, the lessee must submit a completed Form MMS-4293 in accordance with paragraph (c)(2) of this section. A transportation allowance may be claimed retroactively for a period of not more than 3 months prior to the first day of the month that Form MMS-4293 is filed with MMS, unless MMS approves a longer period upon a showing of good cause by the lessee. MMS will monitor the allowance deductions to ensure that deductions are reasonable and allowable. When necessary or appropriate, MMS may direct a lessee to modify its estimated or actual transportation allowance deduction.
(2) The transportation allowance for non-arm's-length or no contract situations shall be based upon the lessee's actual costs for transportation during the reporting period, including operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment in accordance with paragraph (b)(2)(iv)(A) of this section, or a cost equal to the depreciable investment in the transportation system multiplied by the rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) which are an integral part of the transportation system.
(i) Allowable operating expenses include: Operations supervision and engineering; operations labor; fuel; utilities; materials; ad valorem property taxes; rent; supplies; and any other directly allocable and attributable operating expense which the lessee can document.
(ii) Allowable maintenance expenses include: Maintenance of the transportation system; maintenance of equipment; maintenance labor; and other directly allocable and attributable maintenance expenses which the lessee can document.
(iii) Overhead attributable and allocable to the operation and maintenance of the transportation system is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses.
(iv) A lessee may use either paragraph (b)(2)(iv)(A) or paragraph (b)(2)(iv)(B) of this section. After a lessee has elected to use either method for a transportation system, the lessee may not later elect to change to the other alternative without approval of MMS.
(A) To compute depreciation, the lessee may elect to use either a straight-line depreciation method based on the life of equipment or on the life of the reserves which the transportation system services, whichever is appropriate, or a unit of production method. After an election is made, the lessee may not change methods without MMS approval. A change in ownership of a transportation system shall not alter the depreciation schedule established by the original transporter/lessee for purposes of the allowance calculation. With or without a change in ownership, a transportation system shall be depreciated only once. Equipment shall not be depreciated below a reasonable salvage value.
(B) MMS shall allow as a cost an amount equal to the allowable capital investment in the transportation system multiplied by the rate of return determined pursuant to paragraph (b)(2)(B)(v) of this section. No allowance shall be provided for depreciation. This alternative shall apply only to transportation facilities first placed in service or acquired after March 1, 1989.
(v) The rate of return shall be the industrial rate associated with Standard and Poor's BBB rating. The rate of return shall be the monthly average as published in Standard and Poor's Bond Guide for the first month of the reporting period of which the allowance is applicable and shall be effective during the reporting period. The rate shall be redetermined at the beginning of each subsequent transportation allowance reporting period (which is determined pursuant to paragraph (c)(2) of this section).
(3) A lessee may apply to MMS for exception from the requirement that it compute actual costs in accordance with paragraphs (b)(1) and (b)(2) of this section. MMS will grant the exception only if the lessee has a rate for the transportation approved by a Federal agency for Indian leases. MMS shall deny the exception request if it determines that the rate is excessive as compared to arm's-length transportation charges by systems, owned by the lessee or others, providing similar transportation services in that area. If there are no arm's-length transportation charges, MMS shall deny the exception request if:
(i) No Federal regulatory agency cost analysis exists and the Federal regulatory agency has declined to investigate pursuant to MMS timely objections upon filing; and
(ii) The rate significantly exceeds the lessee's actual costs for transportation as determined under this section.
(c) Reporting requirements—(1) Arm's-length contracts. (i) With the exception of those transportation allowances specified in paragraphs (c)(1)(v) and (c)(1)(vi) of this section, the lessee shall submit page one of the initial Form MMS-4293 prior to, or at the same time as, the transportation allowance determined pursuant to an arm's-length contract is reported on Form MMS-4430, Solid Minerals Production and Royalty Report.
(ii) The initial Form MMS-4293 shall be effective for a reporting period beginning the month that the lessee is first authorized to deduct a transportation allowance and shall continue until the end of the calendar year, or until the applicable contract or rate terminates or is modified or amended, whichever is earlier.
(iii) After the initial reporting period and for succeeding reporting periods, lessees must submit page one of Form MMS-4293 within 3 months after the end of the calendar year, or after the applicable contract or rate terminates or is modified or amended, whichever is earlier, unless MMS approves a longer period (during which period the lessee shall continue to use the allowance from the previous reporting period). Lessees may request special reporting procedures in unique allowance reporting situations, such as those related to spot sales.
(iv) MMS may require that a lessee submit arm's-length transportation contracts, production agreements, operating agreements, and related documents. Documents shall be submitted within a reasonable time, as determined by MMS.
(v) Transportation allowances that are based on arm's-length contracts and which are in effect at the time these regulations become effective will be allowed to continue until such allowances terminate. For the purposes of this section, only those allowances that have been approved by MMS in writing shall qualify as being in effect at the time these regulations become effective.
(vi) MMS may establish, in appropriate circumstances, reporting requirements that are different from the requirements of this section.
(2) Non-arm's-length or no contract. (i) With the exception of those transportation allowances specified in paragraphs (c)(2)(v) and (c)(2)(vii) of this section, the lessee shall submit an initial Form MMS-4293 prior to, or at the same time as, the transportation allowance determined pursuant to a non-arm's-length contract or no contract situation is reported on Form MMS-4430, Solid Minerals Production and Royalty Report. The initial report may be based on estimated costs.
(ii) The initial Form MMS-4293 shall be effective for a reporting period beginning the month that the lessee first is authorized to deduct a transportation allowance and shall continue until the end of the calendar year, or until the transportation under the non-arm's-length contract or the no contract situation terminates, whichever is earlier.
(iii) For calendar-year reporting periods succeeding the initial reporting period, the lessee shall submit a completed Form MMS-4293 containing the actual costs for the previous reporting period. If the transportation is continuing, the lessee shall include on Form MMS-4293 its estimated costs for the next calendar year. The estimated transportation allowance shall be based on the actual costs for the previous reporting period plus or minus any adjustments that are based on the lessee's knowledge of decreases or increases that will affect the allowance. Form MMS-4293 must be received by MMS within 3 months after the end of the previous reporting period, unless MMS approves a longer period (during which period the lessee shall continue to use the allowance from the previous reporting period).
(iv) For new transportation facilities or arrangements, the lessee's initial Form MMS-4293 shall include estimates of the allowable transportation costs for the applicable period. Cost estimates shall be based upon the most recently available operations data for the transportation system, or, if such data are not available, the lessee shall use estimates based upon industry data for similar transportation systems.
(v) Non-arm's-length contract or no contract-based transportation allowances that are in effect at the time these regulations become effective will be allowed to continue until such allowances terminate. For purposes of this section, only those allowances that have been approved by MMS in writing shall qualify as being in effect at the time these regulations become effective.
(vi) Upon request by MMS, the lessee shall submit all data used to prepare its Form MMS-4293. The data shall be provided within a reasonable period of time, as determined by MMS.
(vii) MMS may establish, in appropriate circumstances, reporting requirements that are different from the requirements of this section.
(viii) If the lessee is authorized to use its Federal-agency-approved rate as its transportation cost in accordance with paragraph (b)(3) of this section, it shall follow the reporting requirements of paragraph (c)(1) of this section.
(3) MMS may establish reporting dates for individual lessees different than those specified in this paragraph in order to provide more effective administration. Lessees will be notified as to any change in their reporting period.
(4) Transportation allowances must be reported as a separate line item on Form MMS-4430, unless MMS approves a different reporting procedure.
(d) Interest assessments for incorrect or late reports and failure to report. (1) If a lessee deducts a transportation allowance on its Form MMS-4430 without complying with the requirements of this section, the lessee shall be liable for interest on the amount of such deduction until the requirements of this section are complied with. The lessee also shall repay the amount of any allowance which is disallowed by this section.
(2) If a lessee erroneously reports a transportation allowance which results in an underpayment of royalties, interest shall be paid on the amount of that underpayment.
(3) Interest required to be paid by this section shall be determined in accordance with 30 CFR 218.202.
(e) Adjustments. (1) If the actual transportation allowance is less than the amount the lessee has taken on Form MMS-4430 for each month during the allowance form reporting period, the lessee shall be required to pay additional royalties due plus interest, computed pursuant to 30 CFR 218.202, retroactive to the first month the lessee is authorized to deduct a transportation allowance. If the actual transportation allowance is greater than the amount the lessee has estimated and taken during the reporting period, the lessee shall be entitled to a credit, without interest.
(2) The lessee must submit a corrected Form MMS-4430 to reflect actual costs, together with any payment, in accordance with instructions provided by MMS.
(f) Other transportation cost determinations. The provisions of this section shall apply to determine transportation costs when establishing value using a net-back valuation procedure or any other procedure that requires deduction of transportation costs.
[61 FR 5481, Feb. 12, 1996, as amended at 64 FR 43289, Aug. 10, 1999; 66 FR 45769, Aug. 30, 2001]
§ 206.462
[Reserved]
§ 206.463
In-situ and surface gasification and liquefaction operations.
If an ad valorem Federal coal lease is developed by in-situ or surface gasification or liquefaction technology, the lessee shall propose the value of coal for royalty purposes to MMS. MMS will review the lessee's proposal and issue a value determination. The lessee may use its proposed value until MMS issues a value determination.
[61 FR 5481, Feb. 12, 1996, as amended at 64 FR 43289, Aug. 10, 1999]
§ 206.464
Value enhancement of marketable coal.
If, prior to use, sale, or other disposition, the lessee enhances the value of coal after the coal has been placed in marketable condition in accordance with § 206.456(h) of this subpart, the lessee shall notify MMS that such processing is occurring or will occur. The value of that production shall be determined as follows:
(a) A value established for the feedstock coal in marketable condition by application of the provisions of § 206.456(c)(2) (i) through (iv) of this subpart; or,
(b) In the event that a value cannot be established in accordance with paragraph (a) of this section, then the value of production will be determined in accordance with § 206.456(c)(2)(v) of this subpart and the value shall be the lessee's gross proceeds accruing from the disposition of the enhanced product, reduced by MMS-approved processing costs and procedures including a rate of return on investment equal to two times the Standard and Poor's BBB bond rate applicable under § 206.458(b)(2)(v) of this subpart.
[61 FR 5481, Feb. 12, 1996, as amended 64 FR 43289, Aug. 10, 1999]
Pt. 207

PART 207—SALES AGREEMENTS OR CONTRACTS GOVERNING THE DISPOSAL OF LEASE PRODUCTS

Subpart A—General Provisions
Sec.
207.1
Required recordkeeping.
207.2
Definitions.
207.3
Contracts made pursuant to new form leases.
207.4
Contracts made pursuant to old form leases.
207.5
Contract and sales agreement retention.
Subpart B—Oil, Gas and OCS Sulfur, General [Reserved]
Subpart C—Federal and Indian Oil [Reserved]
Subpart D—Federal and Indian Gas [Reserved]
Subpart E—Solid Minerals, General [Reserved]
Subpart F—Coal [Reserved]
Subpart G—Other Solid Minerals [Reserved]
Subpart H—Geothermal Resources [Reserved]
Subpart I—OCS Sulfur [Reserved]

Authority:
5 U.S.C. 301 et seq.; 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. 3716 et seq.; 31 U.S.C. 9701; 43 U.S.C. 1301 et seq.; 43 U.S.C. 1331 et seq.; and 43 U.S.C. 1801 et seq.

Source:
53 FR 1225, Jan. 15, 1988, unless otherwise noted.

Subpart A—General Provisions
§ 207.1
Required recordkeeping.
(a) The information collection and recordkeeping requirements contained in this part have been approved by OMB under 44 U.S.C. 3501 et seq. and assigned OMB Clearance Number 1010-0061. The information collected will be used to determine a proper transportation allowance for the cost of transporting royalty oil from the lease to a delivery point remote from the lease. The information is required in order to obtain a benefit and is collected in accordance with the Federal Oil and Gas Royalty Management Act of 1982, 30 U.S.C. 1701 et seq.
(b) Public reporting burden is estimated to average 30 minutes per year for each record keeper to maintain copies of sales contracts, agreements, or other documents relevant to the valuation of production. Send any comments regarding this burden estimate or any other aspect of this requirement to the Information Collection Clearance Officer, Minerals Management Service, 381 Elden Street, Herndon, VA 22070, and to the Office of Information and Regulatory Affairs, Office of Management and Budget, Paperwork Reduction Project 1010-0061, Washington, DC 20503.
[57 FR 41864, Sept. 14, 1992, as amended at 58 FR 64901, Dec. 10, 1994]
§ 207.2
Definitions.
The definitions in part 206 of this title are applicable to this part.
§ 207.3
Contracts made pursuant to new form leases.
On November 29, 1950 (15 FR 8585), a new lease form was adopted (Form 4-1158, 15 FR 8585) containing provisions whereby the lessee agrees that nothing in any contract or other arrangement made for the sale or disposal of oil, gas, natural gasoline, and other products of the leased land, shall be construed as modifying any of the provisions of the lease, including, but not limited to, provisions relating to gas waste, taking royalty-in-kind, and the method of computing royalties due as based on a minimum valuation and in accordance with the oil and gas valuation regulations. A contract or agreement pursuant to a lease containing such provisions may be made without obtaining prior approval of the United States as lessor, but must be retained as provided in § 207.5 of this subpart.
§ 207.4
Contracts made pursuant to old form leases.
(a) Old form leases are those containing provisions prohibiting sales or disposal of oil, gas, natural gasoline, and other products of the lease except in accordance with a contract or other arrangement approved by the Secretary of the Interior, or by the Director of the Minerals Management Service or his/her representative. A contract or agreement made pursuant to an old form lease may be made without obtaining approval if the contract or agreement contains either the substance of or is accompanied by the stipulation set forth in paragraph (b) of this section, signed by the seller (lessee or operator).
(b) The stipulation, the substance of which must be included in the contract, or be made the subject matter of a separate instrument properly identifying the leases affected thereby, is as follows:
It is hereby understood and agreed that nothing in the written contract or in any approval thereof shall be construed as affecting any of the relations between the United States and its lessee, particularly in matters of gas waste, taking royalty in kind, and the method of computing royalties due as based on a minimum valuation and in accordance with the terms and provisions of the oil and gas valuation regulations applicable to the lands covered by said contract.
§ 207.5
Contract and sales agreement retention.
Copies of all sales contracts, posted price bulletins, etc., and copies of all agreements, other contracts, or other documents which are relevant to the valuation of production are to be maintained by the lessee and made available upon request during normal working hours to authorized MMS, State or Indian representatives, other MMS or BLM officials, auditors of the General Accounting Office, or other persons authorized to receive such documents, or shall be submitted to MMS within a reasonable period of time, as determined by MMS. Any oral sales arrangement negotiated by the lessee must be placed in written form and retained by the lessee. Records shall be retained in accordance with 30 CFR part 212.
Subpart B—Oil, Gas, and OCS Sulfur, General [Reserved]
Subpart C—Federal and Indian Oil [Reserved]
Subpart D—Federal and Indian Gas [Reserved]
Subpart E—Solid Minerals, General [Reserved]
Subpart F—Coal [Reserved]
Subpart G—Other Solid Minerals [Reserved]
Subpart H—Geothermal Resources [Reserved]
Subpart I—OCS Sulfur [Reserved]
Pt. 208

PART 208—SALE OF FEDERAL ROYALTY OIL

Subpart A—General Provisons
Sec.
208.1
General.
208.2
Definitions.
208.3
Information collection.
208.4
Royalty oil sales to eligible refiners.
208.5
Notice of royalty oil sale.
208.6
General application procedures.
208.7
Determination of eligibility.
208.8
Transportation and delivery.
208.9
Agreements.
208.10
Notices.
208.11
Surety requirements.
208.12
Payment requirements.
208.13
Reporting requirements.
208.14
Civil and criminal penalties.
208.15
Audits.
208.16
How to appeal a contracting officer's decision that you receive.
208.17
Suspensions for national emergencies.

Authority:
5 U.S.C. 301 et seq.; 30 U.S.C. 181 et seq., 351 et seq., 1701 et seq.; 31 U.S.C. 9701; 41 U.S.C. 601 et seq.; 43 U.S.C. 1301 et seq., 1331 et seq., and 1801 et seq.

Source:
52 FR 41913, Oct. 30, 1987, unless otherwise noted.

Subpart A—General Provisions
§ 208.1
General.
The regulations in this part govern the sale of royalty oil by the United States to eligible refiners. The regulations apply to royalty oil from leases on Federal lands onshore and on the Outer Continental Shelf (OCS).
§ 208.2
Definitions.
Allotment means the quantity of royalty oil that DOI determines is available to each eligible refiner that has applied for a portion of the total volume of royalty oil offered in a given royalty oil sale.
Application means the formal written request to DOI on Form MMS-4070 by an eligible refiner interested in purchasing a quantity of royalty oil from the approximate volume announced by DOI in a given “Notice of Availability of Royalty Oil.”
Area or Region means the geographic territory having Federal oil and gas leases over which MMS has jurisdiction, unless the context in which those words are used indicates that a different meaning is intended.
Contracting officer means the Director, his or her delegate, or the person designated under a royalty oil purchase contract.
Contracting officer's decision means an MMS order or decision that a contracting officer issues under this part to a purchaser of oil under a royalty oil purchase contract.
Delivery point means the point where the lessor, in accordance with lease terms, directs the lessee to deliver royalty oil to a purchaser. Title to the royalty oil, or to the quantity thereof in a commingled stream, passes from the Federal Government to the purchaser at this designated point, which is specified in the royalty oil contract. For onshore leases, the delivery point will be on or adjacent to the lease, except as provided in § 208.8(a) of this part. In instances where an onshore delivery point is designated for offshore royalty oil, such point generally will be the first onshore point where the price of the oil, including transportation costs, can be determined and where the purchaser can either exchange or take delivery of the oil. The Government does not guarantee physical access to the oil at such point.
Director means the Director of MMS, who is responsible for its overall direction, or his or her delegate(s).
DOI means the Department of the Interior, including the Secretary or his or her delegate(s).
Eligible refiner means a refiner of crude oil that meets the following criteria for eligibility to purchase royalty oil:
(1) For the purchase of royalty oil from onshore leases, it means a refiner that qualifies as a small and independent refiner as those terms are defined in sections 3(3) and 3(4) of the Emergency Petroleum Allocation Act, 15 U.S.C. 751 et seq., except that the time period for determination contained in section 3(3)(A) would be the calendar quarter immediately preceding the date of the applicable “Notice of Availability of Royalty Oil.” A refiner that, together with all persons controlled by, in control of, under common control with, or otherwise affiliated with the refiner, inputs a volume of domestic crude oil from its own production exceeding 30 percent of its total refinery input of crude oil is ineligible to participate in royalty oil sales under this part. Crude oil received in exchange for such refiner's own production is considered to be that refiner's own production for purposes of this section.
(2) For the purchase of royalty oil from leases on the OCS, it means a refiner that qualifies as a small business enterprise under the rules of the Small Business Administration (13 CFR part 121).
Entitlement means the volume of royalty oil from the Federal Government's share of production from a Federal lease which a purchaser is entitled to receive under a royalty oil contract.
Exchange agreement means a written agreement between the purchaser and another person for the exchange of royalty oil purchased under this part for other oil on a volume or equivalent value basis.
Fair market value means the value of oil—(1) Computed at a unit price equivalent to the average unit price at which oil was sold pursuant to a lease during the period for which any royalty or net profit share is accrued or reserved to the United States pursuant to such lease, or
(2) If there were no such sales, or if the Secretary finds that there were an insufficient number of such sales to equitably determine such value, computed at the average unit price at which oil was sold pursuant to other leases in the same region of the OCS during such period, or
(3) If there were no sales of oil from such region during such period, or if the Secretary finds that there are an insufficient number of such sales to equitably determine such value, at an appropriate price determined by the Secretary.
Federal lease means a contractual agreement with the Federal Government which authorizes the exploration, development, and production of oil and gas on Federal lands onshore or on the OCS.
Interim sale means a sale conducted as a result of substantial additional royalty oil becoming available in a specific area prior to the scheduled expiration date of royalty oil contracts in effect for that area.
Lessee means any person to whom the United States issues a lease, or any person who has been assigned an obligation to make royalty or other payments required by the lease.
MMS means the Minerals Management Service of the Department of the Interior.
Notice of Availability of Royalty Oil means a notice published by DOI in the Federal Register (and in other printed media when appropriate, such as a newspaper or magazine of general or specialized circulation) to advise interested parties of the availability of royalty oil for purchase by eligible refiners and the approximate volume of royalty oil available to the applicants.
OCS means the Outer Continental Shelf, as defined in 43 U.S.C. 1331(a).
OCSLA means the Outer Continental Shelf Lands Act (43 U.S.C. 1331 et seq., as amended by 43 U.S.C. 1801 et seq.).
Oil means a mixture of hydrocarbons that existed in the liquid phase in natural underground reservoirs and remains liquid at atmospheric pressure after passing through surface separating facilities and is marketed or used as such. Condensate recovered in lease separators or field facilities is considered to be oil.
Operator means any person, including a lessee, who has control of or who manages operations on an oil and gas lease site on Federal onshore lands or on the OCS.
Payor means any person responsible for reporting royalties from a Federal lease or leases on Form MMS-2014.
Person means any individual, firm, corporation, association, partnership, consortium, or joint venture.
Preference eligible refiner means an eligible refiner with at least one operating refinery which is located within the area designated as the preference eligible area in the “Notice of Availability of Royalty Oil.” A refiner may be deemed to be a preference eligible refiner if it owns a refinery located in the preference eligible area which is not operational if the refiner meets the requirements of § 208.7(g) of this part.
Purchaser means anyone who acquires royalty oil sold by DOI under the Federal Government's Royalty-in-Kind (RIK) Program and who has a contractual obligation under an agreement to purchase royalty oil.
Reallocation means an offering of royalty oil previously allocated in a specific sale but subsequently turned back to MMS. A reallocation would only be made if substantial amounts of royalty oil are turned back.
Refined petroleum product means gasoline, kerosene, distillates (including Number 2 fuel oil), refined lubricating oils, or diesel fuel.
Royalty oil means that amount of oil that DOI takes in kind in partial or full satisfaction of a lessee's royalty or net profit share obligations as determined by whatever lease interest the lessee holds under an applicable mineral leasing law.
Secretary means the Secretary of the Department of the Interior or his/her delegate(s).
Section 6 lease means an oil and gas lease originally issued by any State and currently maintained in effect pursuant to section 6 of the OCSLA.
Section 8 lease means an oil and gas lease originally issued by the United States pursuant to section 8 of the OCSLA.
[52 FR 41913, Oct. 30, 1987; 52 FR 45528, Nov. 30, 1987, as amended at 58 FR 64901, Dec. 10, 1993; 64 FR 26251, May 13, 1999]
§ 208.3
Information collection.
The information collection requirements contained in this part have been approved by OMB under 44 U.S.C. 3501 et seq. The form, filing date, and approved OMB clearance number are identified in 30 CFR 210.10.
[58 FR 64901, Dec. 10, 1993]
§ 208.4
Royalty oil sales to eligible refiners.
(a) Determination to take royalty oil in kind. The Secretary may evaluate crude oil market conditions from time to time. The evaluation will include, among other things, the availability of crude oil and the crude oil requirements of the Federal Government, primarily those requirements concerning matters of national interest and defense. The Secretary will review these items and will determine whether eligible refiners have access to adequate supplies of crude oil and whether such oil is available to eligible refiners at equitable prices. Such determinations may be made on a regional basis. The determination by the Secretary shall be published in the Federal Register concurrent with or included in the “Notice of Availability of Royalty Oil” required by 30 CFR 208.5.
(b) Sale to eligible refiners. (1) Upon a determination by the Secretary under paragraph (a) of this section that eligible refiners do not have access to adequate supplies of crude oil at equitable prices, the Secretary, at his or her discretion, may elect to take in kind some or all of the royalty oil accruing to the United States from oil and gas leases on Federal lands onshore and on the OCS. The Secretary may authorize MMS to offer royalty oil for sale to eligible refiners only for use in their refineries and not for resale (other than under an exchange agreement).
(2) All sales of royalty oil from onshore leases will be priced at the royalty value that would have been determined for that oil pursuant to 30 CFR part 206 had the royalties been paid in value rather than taken in kind. All sales of royalty oil from OCS leases will be priced at the fair market value of the oil including associated transportation costs to the designated delivery point, if applicable.
(3) An eligible refiner must have a representative at a sale in order to participate. The Secretary may, at his or her discretion, establish purchase limitations and withhold any royalty oil from any offering.
(c) Upon a determination by the Secretary under paragraph (a) of this section that eligible refiners do have access to adequate supplies of crude oil at equitable prices, MMS will not take royalties in kind from oil and gas leases for exclusive sale to such refiners. Such determinations may be made on a regional basis.
(d) Interim sales. The MMS generally will not conduct interim sales. However, interim sales may be held at the discretion of the Secretary if substantial addition royalty oil becomes available. The potentially eligible refiners, individually or collectively, must submit documentation demonstrating that adequate supplies of crude oil at equitable prices are not available for purchase. Although sufficient documentation must be submitted, it is not mandatory for each potentially eligible refiner to participate in a submission of such documentation to be determined eligible. The documentation must be submitted to MMS for a determination as to whether an interim sale is needed.
[52 FR 41913, Oct. 30, 1987, as amended at 66 FR 28657, May 24, 2001]
§ 208.5
Notice of royalty oil sale.
If the Secretary decides to take royalty oil in kind for sale to eligible refiners, MMS will issue a “Notice of Availability of Royalty Oil” specifying the manner in which the sale is to be effected, the approximate quantity of royalty oil to be offered, information required in applications, the closing date for the receipt of applications for royalty oil, and other general administrative details concerning the application, allocation, and contract award process for the royalty oil. The Notice will describe generally the terms under which the royalty oil contracts will be awarded and will specify which applicants will be deemed preference eligible refiners in the sale proceedings. The Notice will also contain guidelines for reallocation procedures in the event substantial quantities of royalty oil sold in that specific sale are subsequently turned back to MMS. Only those purchasers that hold ongoing contracts from that specific sale will be allowed to participate in any reallocation, which would be voluntary, and then only if they continue to meet eligibility requirements as set forth in 30 CFR 208.2 and 208.7. If a reallocation is held prior to the effective date of the contracts as specified in the “Notice of Availability of Royalty Oil”, all eligible refiners that selected a lease or leases in that specific sale would be allowed to participate, pursuant to the procedures in the Notice.
§ 208.6
General application procedures.
(a) To apply for the purchase of royalty oil, an applicant must file a Form MMS-4070 with MMS in accordance with instructions provided in the “Notice of Availability of Royalty Oil” and in accordance with any instructions issued by MMS for completion of Form MMS-4070. The applicant will be required to submit a letter of intent from a qualified financial institution stating that it would be granted surety coverage for the royalty oil for which it is applying, or other such proof of surety coverage, as deemed acceptable by MMS. The letter of intent must be submitted with a completed Form MMS-4070.
(b) In addition to any other application requirements specified in the Notice, the following information is required on Form MMS-4070 at the time of application:
(1) Name and address of the applicant, the location of the applicant's refinery or refineries, and disclosure of the applicant's affiliation with any other persons.
(2) The capacity of the applicant's refineries in barrels of crude oil throughput per calendar day and a tabulation for the past 12 months of oil processed for each refinery, identified as to source (from own production or from other sources).
(3) Identification of any Government royalty oil contracts under which the applicant is currently receiving royalty oil.
(4) Identification of the locations (area/region and State) where the applicant proposes to purchase royalty oil, the volume of oil requested, and the specific refineries in which the oil will be refined.
(5) A certification from the applicant that it is an eligible refiner for the purchase of Government royalty oil, as defined in § 208.2 of this part.
[52 FR 41913, Oct. 30, 1987, as amended at 58 FR 64901, Dec. 10, 1993]
§ 208.7
Determination of eligibility.
(a) The MMS will examine each application and may request additional information if the information in the application is inadequate. An application received after the close of the application period will be rejected. If additional information is requested by MMS, it must be received by the time specified or the application will be rejected.
(b) After the close of the application period and the receipt of any additional requested information, MMS will determine which applicants may participate in the royalty oil sale and the quantity of royalty oil which each applicant is authorized to purchase.
(c) When applications are filed by two or more eligible refiners for the same royalty oil, the oil will be allocated among such applicants on an equitable basis as determined by MMS. Preference eligible refiners will be given priority in the allocation procedures in sales and subsequent reallocations of royalty oil.
(d) No eligible refiner shall be awarded contracts for volumes of royalty oil that, when added to volumes of other Federal royalty oil being received, are in excess of 60 percent of the combined refinery capacity of that refiner.
(e) The MMS may exclude any section 6 lease from a royalty oil sale.
(f) If two or more eligible refiners are related through common ownership or control or otherwise affiliated, only one of them shall be entitled to an allotment of royalty oil from a specific sale.
(g) Any applicant whose refinery is not in operation during the 60-day period prior to the date of the royalty oil sale shall not be entitled to participate in the sale unless such applicant self- certifies and demonstrates to the satisfaction of MMS that it will begin operations by the first month in which oil becomes available under a royalty oil contract. If operations do not begin by that month, MMS will terminate the contract.
(h) Applicants or purchasers that have delinquent balances with MMS as of the date of a royalty oil sale or subsequent reallocation will not be allowed to participate in that sale or reallocation. If a person which is controlled by, in control of, under common control with, or otherwise affiliated with an applicant or purchaser has such delinquent balances, the applicant or purchaser will not be allowed to participate in a royalty oil sale or reallocation. To the extent a purchaser or affiliated person has appealed a billing and posted a surety instrument in accordance with the contract terms and applicable MMS regulations or other law, the balance shall not be considered delinquent.
(i) A purchaser must meet the eligibility criteria on the date of contract issuance. However, a change in a purchaser's eligibility status during the term of the contract will not affect the purchaser's right to continue that contract until its term expires, including any extensions thereof.
[52 FR 41913, Oct. 30, 1987, as amended at 58 FR 64901, Dec. 10, 1993]
§ 208.8
Transportation and delivery.
(a) The lessee shall deliver royalty oil from onshore leases to the purchaser at a point on or adjacent to the lease pursuant to the terms of the lease. If the purchaser does not have access to its onshore royalty oil entitlement at facilities on or adjacent to the lease, the operator of the lease must designate an alternate delivery point at no additional cost to the purchaser or the Government. The purchaser must have physical access to the oil at the alternate delivery point and such point must be approved by MMS.
(b) The lessee shall deliver royalty oil from section 8 offshore leases issued after September 1969 at a delivery point to be designated by MMS. The lessee shall deliver royalty oil from section 8 offshore leases issued before October 1969 or from section 6 leases at a delivery point to be designated by the lessee. If the delivery point is on or immediately adjacent to the lease, the royalty oil will be delivered without cost to the Federal Government as an undivided portion of production in marketable condition at pipeline connections or other facilities provided by the lessee, unless other arrangements are approved by MMS. If the delivery point is not on or immediately adjacent to the lease, MMS will reimburse the lessee for the reasonable cost of transportation to such point in an amount not to exceed the transportation allowance determined pursuant to 30 CFR part 206. The MMS will include such transportation costs in the price charged for the oil taken in kind to reflect the value of the oil at the delivery point. Arrangements for delivery of the royalty oil from, or exchange of the oil at, the delivery point, and related transportation costs, are the responsibility of the purchaser of the royalty oil. In addition, quality differentials between the royalty oil to which a purchaser is entitled and the oil which is made available at the delivery point are matters to be resolved between the purchaser and the operator.
(c) When the purchaser has physical access to the royalty oil at the delivery point, the lessee shall deliver such oil in marketable condition at pipeline connections or other facilities designated by MMS. If the lessee is unable to provide the royalty portion of actual production from the lease, the lessee must provide crude oil to the purchaser which is equivalent in volume or value to the royalty oil to which the purchaser is entitled. The lessee will deliver the royalty oil to the purchaser during normal operating hours and in reasonable quantities and intervals. The lessee will make available and the purchaser will accept delivery of the royalty oil entitlement no later than the last day of the calendar month immediately following the calendar month in which the oil was produced. Failure to accept deliveries shall constitute grounds for the termination of the contract.
(d) Upon termination of deliveries under a royalty oil contract, the transportation allowance and delivery point designation authorized by this section no longer will remain in effect.
§ 208.9
Agreements.
(a) A purchaser must submit to MMS two copies of any written third-party agreements, or two copies of a full written explanation of any oral third-party agreements, relating to the method and costs of delivery of royalty oil, or crude oil exchanged for the royalty oil, from the point of delivery under the contract to the purchaser's refinery. In addition, the purchaser must submit copies of agreements pertaining to quality differentials which may occur between leases and delivery points.
(b) A purchaser may not sell royalty oil which it purchases pursuant to this part except for purposes of an exchange for other crude oil on a volume or equivalent value basis.
(c) Royalty oil purchased under this part, or crude oil received in exchange for such royalty oil, must be processed into refined petroleum products in the purchaser's refinery.
§ 208.10
Notices.
(a) The MMS shall notify each operator, by certified mail, of the Secretary's decision to take royalty oil in kind. This notice shall be mailed at least 45 days in advance of the effective date of delivery and will specify delivery points for offshore oil for OCS leases issued after September 1969.
(b) Deliveries of royalty oil may be partially terminated only with the written approval of the Director, MMS.
(c) Before terminating the delivery of royalty oil taken in kind, MMS, if possible, will notify each operator by certified mail of the change in requirements at least 30 days in advance of the effective date.
(d) After MMS notification that royalty oil will be taken in kind, the operator shall be responsible for notifying each working interest on the Federal lease. As soon as practicable after the date of each royalty oil sale, MMS will publish in the Federal Register a notice of the leases from which royalty oil will be taken, the purchasers of the royalty oil, and the leases from which royalty oil deliveries will be discontinued on terminated contracts.
(e) A purchaser cannot transfer, assign, or sell its rights or interest in a royalty oil contract without written approval of the Director, MMS. If the purchaser changes ownership or its assets are sold or liquidated for any reason, it cannot transfer, assign, or sell its rights or interest in the royalty oil contract without written approval of the Director, MMS. Without express written consent from MMS for a change in ownership, the royalty oil contract shall be terminated. The successor company must meet the definition of an eligible refiner in § 208.2 of this part for MMS to consider assignment of the royalty oil contract.
§ 208.11
Surety requirements.
(a) The eligible purchaser, prior to execution of the contract, shall furnish an “MMS-specified surety instrument,” in an amount equal to the estimated value of royalty oil that could be taken by the purchaser in a 99-day period, plus related administrative charges. The MMS may require the purchaser to increase the amount of the surety instrument when necessary to protect the Government's interest or may allow the purchaser to decrease the amount of the surety instrument where necessary to further the purposes of the Royalty-in-Kind Program.
(b) If a letter of credit is furnished as the surety instrument, it must be effective for a 9-month period beginning the first day the royalty oil contract is effective, with a clause providing for automatic renewal monthly for a new 9-month period. The purchaser or its surety company may elect not to renew the letter of credit at any monthly anniversary date, but must notify MMS of its intent not to renew at least 30 days prior to the anniversary date. The MMS may grant the purchaser 45 days to obtain a new surety instrument. If no replacement surety instrument is provided, MMS will terminate the contract effective at least 6 months prior to the expiration date of the letter of credit. Notwithstanding the above provisions, the letter of credit also may contain a clause providing for automatic termination 6 months after the royalty oil contract terminates. If a certificate of deposit is furnished as the surety instrument, it must be effective for the life of the contract plus 6 months after the royalty oil contract terminates.
(c) For the purposes of this section, an “MMS-specified surety instrument” means either: an MMS-specified surety bond, an MMS-specified irrevocable letter of credit, or a financial institution book-entry certificate of deposit.
(d) The “MMS-specified surety instrument” shall be in a form specified by MMS instructions or approved by MMS. A bond must be issued by a qualified surety company that has been approved by the Department of the Treasury. An irrevocable letter of credit or a certificate of deposit must be from a financial institution acceptable to MMS. The MMS will use a bank rating service to determine whether a financial institution has an acceptable rating to provide a surety instrument deemed adequate to indemnify the Government from loss or damage.
(e) All surety instruments must be in a form acceptable to MMS and must include such other specific requirements as MMS may require adequately to protect the Government's interests.
[58 FR 64901, Dec. 10, 1993]
§ 208.12
Payment requirements.
(a) All payments to MMS by a purchaser of royalty oil will be due on the date and at the location specified in the contract, or, if there is no contractual provision, as specified by MMS. The purchaser shall tender all payments to MMS in accordance with 30 CFR 218.51. Payments made by a payor pursuant to the requirements of paragraph (b) of this section and § 208.13 also shall be tendered in accordance with 30 CFR 218.51.
(b)(1) Payments from a purchaser of royalty oil not received by MMS when due, or that portion of the payment less than the full amount due, will be subject to a late payment charge equivalent to an interest assessment on the amount past due for the number of days that the payment is late at the underpayment rate applicable under section 6621 of the Internal Revenue Code of 1954.
(2) The MMS may assess interest to a payor for any underpayments which are the result of the payor's late or underreporting, or for adjustments reported by the payor, or made as a result of audit, reconciliation, or other procedures. The interest for late payment and underpayment will be assessed pursuant to 30 CFR 218.54.
(c) If payment for royalty oil is not received by the due date specified in the contract, a notice of nonreceipt will be sent to the purchaser by certified mail. If payment is not received by MMS within 15 days from the date of such notice, MMS may cancel the contract and collect under the MMS-specified surety instrument. See § 208.11.
(d) If the purchaser disagrees with the amount of payment due, it must pay the amount due as computed by MMS, unless the purchaser appeals the amount and posts an MMS-specified surety instrument pursuant to the provisions of 30 CFR part 243. The MMS may, at its discretion, waive the appeal surety requirements if it determines that the contract surety instrument is sufficient protection for an amount under appeal.
[52 FR 41913, Oct. 30, 1987, as amended at 64901, Dec. 10, 1993]
§ 208.13
Reporting requirements.
If MMS underbills a purchaser under a royalty oil contract because of a payor's underreporting or failure to report on Form MMS-2014 pursuant to 30 CFR 210.52, the payor will be liable for payment of such underbilled amounts plus interest if they are unrecoverable from the purchaser or the surety instrument related to the contract.
[58 FR 64902, Dec. 10, 1993]
§ 208.14
Civil and criminal penalties.
Failure to abide by the regulations in this part may result in civil and criminal penalties being levied on that person as specified in sections 109 and 110 of the Federal Oil and Gas Royalty Management Act of 1982, 30 U.S.C. 1719-20, and regulations at 30 CFR part 241. Civil penalties applicable under the OCSLA and the Mineral Leasing Act of 1920 may also be imposed.
§ 208.15
Audits.
Audits of the accounts and books of lessees, operators, payors, and/or purchasers of royalty oil taken in kind may be made annually or at such other times as may be directed by MMS. Such audits will be for the purpose of determining compliance with applicable statutes, regulations, and royalty oil contracts.
§ 208.16
How to appeal a contracting officer's decision that you receive.
If you receive a contracting officer's decision, you may:
(a) Appeal that decision to the Board of Contract Appeals in the Office of Hearings and Appeals, Office of the Secretary, in accordance with the procedures provided in 43 CFR part 4, subpart C; or
(b) File an action in the United States Court of Federal Claims.
[64 FR 26251, May 13, 1999]
§ 208.17
Suspensions for national emergencies.
The Secretary of the Department of the Interior, upon a recommendation by the Secretary of Defense or the Secretary of Energy and with the approval of the President, may suspend operations under these regulations and suspend royalty oil contracts during a national emergency declared by the Congress or the President.
Pt. 210

PART 210—FORMS AND REPORTS

Subpart A—General Provisions
Sec.
210.01
What is the purpose of this subpart?
210.02
To whom do these regulations apply?
210.10
What are the OMB-approved information collections?
210.20
What if I disagree with the burden hour estimates?
210.21
How do I report my taxpayer identification number?
210.30
What are my responsibilities as a reporter/payor?
210.40
Will MMS keep the information I provide confidential?

Subpart B—Royalty Reports—Oil, Gas, and Geothermal Resources
210.50
What is the purpose of this subpart?
210.51
Who must submit royalty reports?
210.52
What royalty reports must I submit?
210.53
When are my royalty reports and payments due?
210.54
Must I submit this royalty report electronically?
210.55
May I submit this royalty report manually?
210.56
Where can I find more information on how to complete the royalty report?
210.60
What definitions apply to this subpart?

Subpart C—Production Reports—Oil and Gas
210.100
What is the purpose of this subpart?
210.101
Who must submit production reports?
210.102
What production reports must I submit?
210.103
When are my production reports due?
210.104
Must I submit these production reports electronically?
210.105
May I submit these production reports manually?
210.106
Where can I find more information on how to complete these production reports?

Subpart D—Special-Purpose Forms and Reports—Oil, Gas, and Geothermal Resources
210.150
What is the purpose of this subpart?
210.151
What reports must I submit to claim an excess allowance?
210.152
What reports must I submit to claim allowances on an Indian lease?
210.153
What reports must I submit for Indian gas valuation purposes?
210.154
What documents or other information must I submit for Federal oil valuation purposes?
210.155
What reports must I submit for Federal onshore stripper oil properties?
210.156
What reports must I submit for net profit share leases?
210.157
What reports must I submit to suspend an MMS order under appeal?
210.158
What reports must I submit to designate someone to make my royalty payments?

Subpart E—Production and Royalty Reports—Solid Minerals
210.200
What is the purpose of this subpart?
210.201
How do I submit Form MMS-4430, Solid Minerals Production and Royalty Report?
210.202
How do I submit sales summaries?
210.203
How do I submit sales contracts?
210.204
How do I submit facility data?
210.205
What reports must I submit to claim allowances on Indian coal leases?
210.206
Will I need to submit additional documents or evidence to MMS?
210.207
How will information submissions be kept confidential?
Subpart F—Coal [Reserved]
Subpart G—Other Solid Minerals [Reserved]

Subpart H—Geothermal Resources
210.350
Definitions.
210.351
Required recordkeeping.
210.352
Special forms and reports.
210.353
Monthly report of sales and royalty.
210.354
Reporting instructions.
Subpart I—OCS Sulfur [Reserved]

Authority:
5 U.S.C. 301 et seq.; 25 U.S.C. 396, 2107; 30 U.S.C. 189, 190, 359, 1023, 1751(a); 31 U.S.C. 3716, 9701; 43 U.S.C. 1334, 1801 et seq.; and 44 U.S.C. 3506(a).

Subpart A—General Provisions

Source:
73 FR 15892, Mar. 26, 2008, unless otherwise noted.
§ 210.01
What is the purpose of this subpart?
This subpart identifies information collections required by the Minerals Management Service (MMS), Minerals Revenue Management (MRM), in the normal course of operations. This information is submitted by various parties associated with Federal and Indian leases such as lessees, designees, and operators. The information collected meets the MMS congressionally mandated accounting and auditing responsibilities relating to Federal and Indian minerals revenue management. Information collected regarding production, royalties, and other payments due the Government from activities on leased Federal or Indian land is authorized by the Federal Oil and Gas Royalty Management Act of 1982, as amended (30 U.S.C. 1701 et seq.), as well as 43 U.S.C. 1334 and 30 U.S.C. 189, 359, 396, and 396d for oil and gas production; and by 30 U.S.C. 189, 359, 396, and 396d for solid minerals production.
§ 210.02
To whom do these regulations apply?
The regulations apply to any person, referred to in this subpart as “you,” “your,” or “reporter/payor,” who is a lessee under any Federal or Indian lease for any mineral or who is assigned or assumes an obligation to report data or make payment to MMS. The term reporter/payor may include lessees, designees, operators, purchasers, reporters, other payors, and working interest owners, but is not restricted to these parties. This section does not affect the liability to pay and report royalties as established by other regulations, laws, and the lease terms.
§ 210.10
What are the OMB-approved information collections?
The information collection requirements identified in this subpart have been approved by the Office of Management and Budget (OMB) under 44 U.S.C. 3501 et seq. Detailed information about each information collection request (ICR), including CFR citations, is included on the MMS Web site at http://www.mrm.mms.gov/Laws_R_D/FRNotices/FRNotices.htm. The ICRs and associated MMS form numbers, if applicable, are listed below:
OMB control number and short title | Form or information collected
1010-0073, 30 CFR Part 220, Net Profit Share Payment | No form for the following collection: • Net profit share payment information.
1010-0087, 30 CFR Parts 227, 228, and 229, Delegation to States and Cooperative Activities with States and Indian Tribes | No forms for the following collections: • Written delegation proposal to perform auditing and investigative activities. • Request for cooperative agreement and subsequent requirements.
1010-0090, 30 CFR Part 216, Stripper Royalty Rate Reduction Notification | Form MMS-4377, Stripper Royalty Rate Reduction Notification.
1010-0103, 30 CFR Parts 202 and 206, Indian Oil and Gas Valuation | Form MMS-4109, Gas Processing Allowance Summary Report. Form MMS-4295, Gas Transportation Allowance Report.
| Form MMS-4110, Oil Transportation Allowance Report.
| Form MMS-4411, Safety Net Report.
| Form MMS-4410, Accounting for Comparison [Dual Accounting].
| Form MMS-4393, Request to Exceed Regulatory Allowance Limitation.^1
| 1010-0107, 30 CFR Part 218, Collection of Monies Due the Federal Government | Form MMS-4425, Designation Form for Royalty Payment Responsibility.
| No forms for the following collections: • Cross-lease netting documentation. • Indian recoupment approval.
1010-0119, 30 CFR Part 208, Royalty in Kind (RIK) Oil and Gas | Form MMS-4070, Application for the Purchase of Royalty Oil. Form MMS-4071, Letter of Credit (RIK). Form MMS-4072, Royalty-in-Kind Contract Surety Bond.
| No form for the following collection: • Royalty oil sales to eligible refiners.
1010-0120, 30 CFR Parts 202, 206, 210, 212, 217, and 218, Solid Minerals and Geothermal Collections | Form MMS 4430, Solid Minerals Production and Royalty Report. Form 4292, Coal Washing Allowance Report. Form 4293, Coal Transportation Allowance Report.
| No forms for the following collections: • Facility data—solid minerals. • Sales contracts—solid minerals. • Sales summaries—solid minerals.
1010-0122, 30 CFR Part 243, Suspensions Pending Appeal and Bonding | Form MMS-4435, Administrative Appeal Bond. Form MMS-4436, Letter of Credit. Form MMS-4437, Assignment of Certificate of Deposit.
| No forms for the following collections: • Self bonding. • U.S. Treasury securities.
1010-0136, 30 CFR Parts 202 and 206, Federal Oil and Gas Valuation | Form MMS-4393, Request to Exceed Regulatory Allowance Limitation.^1 No form for the following collection: • Federal oil valuation support information.
1010-0139, 30 CFR Parts 210 and 216, Production Accounting | Form MMS-4054, Oil and Gas Operations Report. Form MMS-4058 (Parts A, B, and C), Production Allocation Schedule Report.
1010-0140, 30 CFR Part 210, Forms and Reports | Form MMS-2014, Report of Sales and Royalty Remittance.
1010-0155, 30 CFR Part 204, Alternatives for Marginal Properties | No form for the following collection: • Notification and relief request for accounting and auditing relief.
1010-0162, CFO Act of 1992, Accounts Receivable Confirmations | No form for the following collection: • Accounts receivable confirmations.
^1 Form MMS-4393 is used for both Federal and Indian oil and gas leases. The form resides with ICR 1010-0136, but the burden hours for Indian leases are included in ICR 1010-0103.
§ 210.20
What if I disagree with the burden hour estimates?
Burden hour estimates are included on the MMS Web site at http://www.mrm.mms.gov/Laws_R_D/FRNotices/FRNotices.htm. Send comments on the accuracy of these burden estimates or suggestions on reducing the burden to the Minerals Management Service, Attention: Information Collection Clearance Officer (OMB Control Number 1010-XXXX [insert appropriate OMB control number]), Mail Stop 4230, 1849 C Street, NW., Washington, DC 20240. 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.
§ 210.21
How do I report my taxpayer identification number?
(a) Before paying or reporting to MMS, you must obtain a payor code (see the MMS Minerals Revenue Reporter Handbook, which is available on the Internet at http://www.mrm.mms.gov/ReportingServices/PDFDocs/RevenueHandbook.pdf; also see § 210.56 for further information on how to obtain a handbook). At the time you request a payor code, you must provide your Employer Identification Number (EIN) by submitting:
(1) An IRS Form W-9; or
(2) An equivalent certification containing:
(i) Your name;
(ii) The name of your business, if different from your name;
(iii) The form of your business entity; for example, a sole proprietorship, corporation, or partnership;
(iv) The address of your business;
(v) The EIN of your business; and
(vi) A signed and dated certification that you are a U.S. citizen or resident alien and that the EIN number provided is correct.
(b) If you are already paying or reporting to MMS but do not have an EIN, MMS may request that you submit an IRS Form W-9 or equivalent certification containing the information required under paragraph (a)(2) of this section.
(c) The collection of this data is not subject to the provisions of the Paperwork Reduction Act because only information necessary to identify the respondent [5 CFR 1320.3(h)] is required.
(d) The EIN you provide to MMS under paragraph (a) of this section:
(1) Means the taxpayer identification number (TIN) of an individual or other person (whether or not an employer), which is assigned under 26 U.S.C. 6011(b), or a corresponding version of prior law, or under 26 U.S.C. 6109;
(2) Must contain nine digits separated by a hyphen as follows: 00-0000000; and
(3) May not be a Social Security Number.
§ 210.30
What are my responsibilities as a reporter/payor?
Each reporter/payor must submit accurate, complete, and timely information to MMS according to the requirements in this part. If you discover an error in a previous report, you must file an accurate and complete amended report within 30 days of your discovery of the error. If you do not comply, MMS may assess civil penalties under 30 CFR part 241.
§ 210.40
Will MMS keep the information I provide confidential?
The MMS will treat information obtained under this part as confidential to the extent permitted by law as specified at 43 CFR part 2.

Subpart B—Royalty Reports—Oil, Gas, and Geothermal Resources

Source:
73 FR 15892, Mar. 26, 2008, unless otherwise noted.
§ 210.50
What is the purpose of this subpart?
The purpose of this subpart is to explain royalty reporting requirements when energy and mineral resources are removed from Federal and Indian oil and gas and geothermal leases and federally approved agreements. This includes leases and agreements located onshore and on the Outer Continental Shelf (OCS).
§ 210.51
Who must submit royalty reports?
(a) Any person who pays royalty to MMS must submit royalty reports to MMS.
(b) Before you pay or report to MMS, you must obtain a payor code. To obtain a payor code, refer to the MMS Minerals Revenue Reporter Handbook for instructions and MMS contact information (also see § 210.56 for information on how to obtain a handbook).
§ 210.52
What royalty reports must I submit?
You must submit a completed Form MMS-2014, Report of Sales and Royalty Remittance, to MMS with:
(a) All royalty payments; and
(b) Rents on nonproducing leases, where specified in the lease.
§ 210.53
When are my royalty reports and payments due?
(a) Completed Forms MMS-2014 for royalty payments and the associated payments are due by the end of the month following the production month (see also § 218.50).
(b) Completed Forms MMS-2014 for rental payments, where applicable, and the associated payments are due as specified by the lease terms (see also § 218.50).
(c) You may submit reports and payments early.
§ 210.54
Must I submit this royalty report electronically?
(a) You must submit Form MMS-2014 electronically unless you qualify for an exception under § 210.55(a).
(b) You must use one of the following electronic media types, unless MMS instructs you differently:
(1) Electronic Data Interchange (EDI)—The direct computer-to-computer interchange of data using standards set forth by the X12 American National Standards Institute (ANSI) Accredited Standards Committee (ASC). The interchange uses the services of a third party with which either party may contract.
(2) Web-based reporting—Reporters/payors may enter report data directly or upload files using the MMS electronic web form located at http://www.mrmreports.net. The uploaded files must be in one of the following formats: the American Standard Code for Information Interchange (ASCII) or Comma Separated Values (CSV) formats. External files created by the sender must be in the proprietary ASCII and CSV file layout formats defined by MMS. These external files can be generated from a reporter's system application.
(c) Refer to our electronic reporting guidelines in the MMS Minerals Revenue Reporter Handbook, for the most current reporting options, instructions, and security measures. The handbook may be found on our Internet Web site or you may call your MMS customer service representative (see § 210.56 for further information on how to obtain a handbook).
§ 210.55
May I submit this royalty report manually?
(a) The MMS will allow you to submit Form MMS-2014 manually if:
(1) You have never reported to MMS before. You have 3 months from the date your first report is due to begin reporting electronically;
(2) You report only rent, minimum royalty, or other annual obligations on Form MMS-2014; or
(3) You are a small business, as defined by the U.S. Small Business Administration, and you have no computer.
(b) If you meet the qualifications under paragraph (a) of this section, you may submit your form manually to MMS by:
(1) U.S. Postal Service regular or express mail addressed to Minerals Management Service, P.O. Box 5810, Denver, Colorado 80217-5810; or
(2) Special courier or overnight mail addressed to Minerals Management Service, Building 85, Room A-614, Denver Federal Center, West 6th Ave. and Kipling Blvd., Denver, Colorado 80225.
§ 210.56
Where can I find more information on how to complete the royalty report?
(a) Specific guidance on how to prepare and submit Form MMS-2014 is contained in the MMS Minerals Revenue Reporter Handbook. The handbook is available on our Internet Web site at http://www.mrm.mms.gov/ReportingServices/Handbooks/Handbks.htm or from MMS at P.O. Box 5760, Denver, Colorado 80217-5760.
(b) Reporters/payors should refer to the handbook for specific guidance on royalty reporting requirements. If you require additional information, you should contact MMS at the above address. A customer service telephone number is also listed in our handbook.
(c) You may find Form MMS-2014 on our Internet Web site at http://www.mrm.mms.gov/ReportingServices/Forms/AFSOil_Gas.htm, or you may request the form from MMS at P.O. Box 5760, Denver, Colorado 80217-5760.
§ 210.60
What definitions apply to this subpart?
Terms used in this subpart have the same meaning as in 30 U.S.C. 1702.

Subpart C—Production Reports—Oil and Gas

Source:
73 FR 15892, Mar. 26, 2008, unless otherwise noted.
§ 210.100
What is the purpose of this subpart?
The purpose of this subpart is to explain production reporting requirements when energy and mineral resources are removed from Federal and Indian oil and gas leases and federally approved agreements. This includes leases and unit and communitization agreements located onshore and on the Outer Continental Shelf (OCS).
§ 210.101
Who must submit production reports?
(a) If you operate a Federal or Indian oil and gas lease or federally approved unit or communitization agreement, you must submit production reports.
(b) Before reporting production to MMS, you must obtain an operator number. To obtain an operator number, refer to the MMS Minerals Production Reporter Handbook for instructions and MMS contact information (also see § 210.106 for information on how to obtain a handbook).
§ 210.102
What production reports must I submit?
(a) Form MMS-4054, Oil and Gas Operations Report. If you operate a Federal or Indian onshore or OCS oil and gas lease or federally approved unit or communitization agreement that contains one or more wells that are not permanently plugged or abandoned, you must submit Form MMS-4054 to MMS:
(1) You must submit Form MMS-4054 for each well for each calendar month, beginning with the month in which you complete drilling, unless:
(i) You have only test production from a drilling well; or
(ii) The MMS tells you in writing to report differently.
(2) You must continue reporting until:
(i) The Bureau of Land Management (BLM) or MMS approves all wells as permanently plugged or abandoned or the lease or unit or communitization agreement is terminated; and
(ii) You dispose of all inventory.
(b) Form MMS-4058, Production Allocation Schedule Report. If you operate an offshore facility measurement point (FMP) handling production from a Federal oil and gas lease or federally approved unit agreement that is commingled (with approval) with production from any other source prior to measurement for royalty determination, you must file Form MMS-4058.
(1) You must submit Form MMS-4058 for each calendar month beginning with the month in which you first handle production covered by this section.
(2) Form MMS-4058 is not required whenever all of the following conditions are met:
(i) All leases involved are Federal leases;
(ii) All leases have the same fixed royalty rate;
(iii) All leases are operated by the same operator;
(iv) The facility measurement device is operated by the same person as the leases/agreements;
(v) Production has not been previously measured for royalty determination; and
(vi) The production is not subsequently commingled and measured for royalty determination at an FMP for which Form MMS-4058 is required under this part.
§ 210.103
When are my production reports due?
(a) The MMS must receive your completed Forms MMS-4054 and MMS-4058 by the 15th day of the second month following the month for which you are reporting.
(b) A report is considered received when it is delivered to MMS by 4 p.m. mountain time at the addresses specified in § 210.105. Reports received after 4 p.m. mountain time are considered received the following business day.
§ 210.104
Must I submit these production reports electronically?
(a) You must submit Forms MMS-4054 and MMS-4058 electronically unless you qualify for an exception under § 210.105.
(b) You must use one of the following electronic media types, unless MMS instructs you differently:
(1) Electronic Data Interchange (EDI)—The direct computer-to-computer interchange of data using standards set forth by the X12 American National Standards Institute (ANSI) Accredited Standards Committee (ASC). The interchange uses the services of a third party with which either party may contract.
(2) Web-based reporting—Reporters/payors may enter report data directly or upload files using the MMS electronic Web form located at http://www.mrmreports.net. The uploaded files must be in one of the following formats: the American Standard Code for Information Interchange (ASCII) or Comma Separated Values (CSV) formats. External files created by the sender must be in the proprietary ASCII and CSV file layout formats defined by MMS. These external files can be generated from a reporter's system application.
(c) Refer to our electronic reporting guidelines in the MMS Minerals Production Reporter Handbook for the most current reporting options, instructions, and security measures. The handbook may be found on our Internet Web site or you may call your MMS customer service representative (see § 210.106 for further information on how to obtain a handbook).
§ 210.105
May I submit these production reports manually?
(a) The MMS will allow you to submit Forms MMS-4054 and MMS-4058 manually if:
(1) You have never reported to MMS before. You have 3 months from the day your first report is due to begin reporting electronically; and
(2) You are a small business, as defined by the U.S. Small Business Administration, and you have no computer.
(b) If you meet the qualifications under paragraph (a) of this section, you may submit your forms manually to MMS by:
(1) U.S. Postal Service regular or express mail addressed to Minerals Management Service, P.O. Box 17110, Denver, Colorado 80217-0110; or
(2) Special courier or overnight mail addressed to Minerals Management Service, Building 85, Room A-614, Denver Federal Center, West 6th Ave. and Kipling Blvd., Denver, Colorado 80225.
§ 210.106
Where can I find more information on how to complete these production reports?
(a) Specific guidance on how to prepare and submit production reports to MMS is contained in the MMS Minerals Production Reporter Handbook. The handbook is available on our Internet Web site at http://www.mrm.mms.gov/ReportingServices/Handbooks/Handbks.htm or from MMS at P.O. Box 17110, Denver, Colorado 80217-0110.
(b) Production reporters should refer to the handbook for specific guidance on production reporting requirements. If you require additional information, you should contact MMS at the above address. A customer service telephone number is also listed in our handbook.
(c) You may find Forms MMS-4054 and MMS-4058 on our Internet Web site at http://www.mrm.mms.gov/ReportingServices/Forms/PAASOff.htm, or you may request the forms from MMS at P.O. Box 17110, Denver, Colorado 80217-0110.

Subpart D—Special-Purpose Forms and Reports—Oil, Gas, and Geothermal Resources

Source:
73 FR 15892, Mar. 26, 2008, unless otherwise noted.
§ 210.150
What is the purpose of this subpart?
This subpart identifies specific special-purpose reports and provides general information, reporting options, and reporting addresses. See § 210.10 for a complete listing of all information collections, including forms and references for specific information collections.
§ 210.151
What reports must I submit to claim an excess allowance?
(a) General. If you are a lessee, you must submit Form MMS-4393, Request to Exceed Regulatory Allowance Limitation, to request approval from MMS to exceed prescribed transportation and processing allowance limits on Federal oil and gas leases and prescribed transportation allowance limits on Indian oil and gas leases under part 206 of this chapter.
(b) Reporting options. You may find Form MMS-4393 on our Web site at http://www.mrm.mms.gov/ReportingServices/Forms/AFSOil_Gas.htm. You may also request the form from MMS at P.O. Box 25165, MS 392B2, Denver, Colorado 80217-0165.
(c) Reporting address. Submit completed Form MMS-4393 as follows:
(1) Complete and submit the form electronically as an e-mail attachment;
(2) Send the form by U.S. Postal Service regular or express mail addressed to Minerals Management Service, P.O. Box 25165, MS 392B2, Denver, Colorado 80217-0165; or
(3) Deliver the form to MMS by special courier or overnight mail addressed to Minerals Management Service, Building 85, Room A-614, MS 392B2, Denver Federal Center, West 6th Ave. and Kipling Blvd., Denver, Colorado 80225.
§ 210.152
What reports must I submit to claim allowances on an Indian lease?
(a) General. You must submit three additional forms to MMS to claim transportation or processing allowances on Indian oil and gas leases:
(1) You must submit Form MMS-4110, Oil Transportation Allowance Report, to claim an allowance for expenses incurred by a reporter/payor to transport oil from the lease site to a point remote from the lease where value is determined under § 206.55 of this chapter.
(2) You must submit Form MMS-4109, Gas Processing Allowance Summary Report, to claim an allowance for the reasonable, actual costs of removing hydrocarbon and nonhydrocarbon elements or compounds from a gas stream under § 206.180 of this chapter.
(3) You must submit Form MMS-4295, Gas Transportation Allowance Report, to claim an allowance for the reasonable, actual costs of transporting gas from the lease to the point of first sale under § 206.178 of this chapter.
(b) Reporting options. You may submit Forms MMS-4110, MMS-4109, and MMS-4295 manually. You may find the forms on our Internet Web site at http://www.mrm.mms.gov/ReportingServices/Forms/AFSOil_Gas.htm, or you may request the forms from MMS at P.O. Box 25165, MS 396B2, Denver, Colorado 80217-0165.
(c) Reporting address. You may submit completed Forms MMS-4110, MMS-4109, and MMS-4295 by:
(1) U.S. Postal Service regular or express mail addressed to Minerals Management Service, P.O. Box 25165, MS 396B2, Denver, Colorado 80217-0165; or
(2) Special courier or overnight mail addressed to Minerals Management Service, Building 85, Room A-614, MS 396B2, Denver Federal Center, West 6th Ave. and Kipling Blvd., Denver, Colorado 80225.
§ 210.153
What reports must I submit for Indian gas valuation purposes?
(a) General. For Indian gas valuation, under certain conditions under § 206.172 of this chapter, lessees must submit the following forms:
(1) Form MMS-4410, Accounting for Comparison (Dual Accounting), Part A or Part B; and/or
(2) Form MMS-4411, Safety Net Report.
(b) Reporting options. You must submit Forms MMS-4410 and MMS-4411 manually. You may find the forms on our Internet Web site at http://www.mrm.mms.gov/ReportingServices/Forms/AFSOil_Gas.htm or request forms from MMS at P.O. Box 25165, MS 396B2, Denver, Colorado 80217-0165.
(c) Reporting address. You must submit completed Forms MMS-4410 and MMS-4411 by:
(1) U.S. Postal Service regular or express mail addressed to Minerals Management Service, P.O. Box 25165, MS 396B2, Denver, Colorado 80217-0165; or
(2) Special courier or overnight mail addressed to Minerals Management Service, Building 85, Room A-614, MS 396B2, Denver Federal Center, West 6th Ave. and Kipling Blvd., Denver, Colorado 80225.
§ 210.154
What documents or other information must I submit for Federal oil valuation purposes?
(a) General. The MMS may require you to submit documents or other information to MMS to support your valuation of Federal oil under part 206 as part of audit compliance.
(b) Reporting options. You must submit the documents or other information manually.
(c) Reporting address. You must submit required documents or other information by:
(1) U.S. Postal Service regular or express mail addressed to Minerals Management Service, P.O. Box 25165, MS 392B2, Denver, Colorado 80217-0165; or
(2) Special courier or overnight mail addressed to Minerals Management Service, Building 85, Room A-614, MS 392B2, Denver Federal Center, West 6th Ave. and Kipling Blvd., Denver, Colorado 80225.
§ 210.155
What reports must I submit for Federal onshore stripper oil properties?
(a) General. Operators who have been granted a reduced royalty rate by the Bureau of Land Management (BLM) under 43 CFR 3103.4-2 must submit Form MMS-4377, Stripper Royalty Rate Reduction Notification, under 43 CFR 3103.4-2(b)(3).
(b) Reporting options. You may find Form MMS-4377 on our Internet Web site at http://www.mrm.mms.gov/ReportingServices/Forms/AFSOil_Gas.htm or request the form from MMS at P.O. Box 17110, Denver, Colorado 80217-0110. You may file the form:
(1) Electronically by filling the form out in electronic format and submitting it to MMS as an e-mail attachment; or
(2) Manually by filling out the form and submitting it by:
(i) U.S. Postal Service regular or express mail addressed to Minerals Management Service, P.O. Box 25165, MS 392B2, Denver, Colorado 80217-0165; or
(ii) Special courier or overnight mail addressed to Minerals Management Service, Building 85, Room A-614, MS 392B2, Denver Federal Center, West 6th Ave. and Kipling Blvd., Denver, Colorado 80225.
§ 210.156
What reports must I submit for net profit share leases?
(a) General. After entering into a net profit share lease (NPSL) agreement, a lessee must report under part 220 of this chapter.
(b) Reporting options. You must submit the required report manually.
(c) Reporting address. You must submit the required documents by:
(1) U.S. Postal Service regular or express mail addressed to Minerals Management Service, P.O. Box 25165, MS 382B2, Denver, Colorado 80217-0165; or
(2) Special courier or overnight mail addressed to Minerals Management Service, Building 85, Room A-614, MS 382B2, Denver Federal Center, West 6th Ave. and Kipling Blvd., Denver, Colorado 80225.
§ 210.157
What reports must I submit to suspend an MMS order under appeal?
(a) General. Reporters/payors or other recipients of MMS Minerals Revenue Management (MRM) orders who appeal an order may be required to post a bond or other surety, under part 243 of this chapter. The MMS accepts the following surety types: Form MMS-4435, Administrative Appeal Bond; Form MMS-4436, Letter of Credit; Form MMS-4437, Assignment of Certificate of Deposit; Self-bonding; and U.S. Treasury Securities.
(b) Reporting options. You must submit these forms and other documents manually. You may find the forms and other documents under Surety Instrument Posting Instructions on our Internet Web site at http://www.mrm.mms.gov/Law_R_D/FRNotices/ICR0122.htm.
(c) Reporting address. You may submit the required forms and other documents as specified in the Surety Instrument Posting Instructions or by:
(1) U.S. Postal Service regular or express mail addressed to Minerals Management Service, P.O. Box 25165, MS 370B2, Denver, Colorado 80217-0165;
(2) Special courier or overnight mail addressed to Minerals Management Service, Building 85, Room A-614, MS 370B2, Denver Federal Center, West 6th Ave. and Kipling Blvd., Denver, Colorado 80225.
§ 210.158
What reports must I submit to designate someone to make my royalty payments?
(a) General. You must submit Form MMS-4425, Designation Form for Royalty Payment Responsibility, if you want to designate a person to make royalty payments on your behalf under § 218.52.
(b) Reporting options. You must submit Form MMS-4425 manually. You may find the form on our Internet Web site at http://www.mrm.mms.gov/ReportingServices/Forms/AFSOil_Gas.htm or request the form from MMS at P.O. Box 5760, Denver, Colorado 80217-5760.
(c) Reporting address. You must submit completed Form MMS-4425 by:
(1) U.S. Postal Service regular or express mail addressed to Minerals Management Service, P.O. Box 25165, MS 357B1, Denver, Colorado 80217-0165; or
(2) Special courier or overnight mail addressed to Minerals Management Service, Building 85, Room A-614, MS 357B1, Denver Federal Center, West 6th Ave. and Kipling Blvd., Denver, Colorado 80225.

Subpart E—Production and Royalty Reports—Solid Minerals

Source:
66 FR 45771, Aug. 30, 2001, unless otherwise noted.
§ 210.200
What is the purpose of this subpart?
This subpart explains your reporting requirements if you produce coal or other solid minerals from Federal or Indian leases. Included are your requirements for reporting production, sales, and royalties.
§ 210.201
How do I submit Form MMS-4430, Solid Minerals Production and Royalty Report?
(a) What to submit. (1) You must submit a completed Form MMS-4430 for—
(i) Production of all coal and other solid minerals from any Federal or Indian lease;
(ii) Sale of any such mineral;
(iii) Any such mineral held in stockpile or inventory; and
(iv) Payment of rents (other than those for which you receive from MMS a Courtesy Notice as defined in § 218.51(a) of this chapter), minimum royalty, deferred bonus, advance royalty, minimum royalty payable in advance, settlements, recoupments, and other financial obligations.
(2) You must submit a completed Form MMS-4430 for any product you sell from a remote storage site. If you sell from five or fewer remote storage sites, you must report sales from each site on separate Forms MMS-4430. If you sell from more than five remote storage sites, you must total the data from all sites and report the summarized data on one Form MMS-4430.
(3) Instructions for completing and submitting Form MMS-4430 are available on our Internet reporting web site or you may contact us toll free at 1-888-201-6416.
(b) When to submit. (1) Unless your lease terms specify a different frequency for royalty payments, you must submit your Form MMS-4430 on or before the end of the month following the month in which you produce any solid mineral, sell any solid mineral, or hold any solid mineral production in stockpile or inventory. However, if the last day of the month falls on a weekend or holiday, your Form MMS-4430 is due on the next business day.
(2) If your lease terms specify a different frequency for royalty payment, then you must submit your Form MMS-4430 on or before the date on which you must pay royalty under the terms of the lease.
(3) You must submit your Form MMS-4430 for payment of rents (other than those for which you receive from MMS a Courtesy Notice as defined in § 218.51(a) of this chapter), minimum royalty, deferred bonus, advance royalty, minimum royalty payable in advance, settlements, recoupments, and other financial obligations on or before the date on which you must pay those obligations under the terms of the lease.
(4) If the information on a previously reported Form MMS-4430 is no longer correct, you must submit a revised Form MMS-4430 by the last day of the month in which you learn that the previously reported information is no longer correct, except when the last day of the month falls on a weekend or holiday. If the last day of the month falls on a weekend or holiday, your revised Form MMS-4430 is due on the first business day of the following month.
(c) How to submit. (1) You must submit Form MMS-4430 electronically using our Internet reporting web site unless you meet the conditions in paragraph (c)(2). We will provide written instructions and a valid login and password before you begin reporting.
(2) You are not required to report electronically if you are a small business as defined by the U.S. Small Business Administration (13 CFR 121.201) and you have no computer, no plans to purchase a computer, and no contract with an electronic reporting service.
(3) If you do not report electronically, you must submit the completed Form MMS-4430 to us at one of the following addresses, unless MMS publishes notice in the Federal Register giving a different address:
(i) For U.S. Postal Service regular mail or Express Mail: Minerals Management Service, Minerals Revenue Management, P.O. Box 5810, Denver, Colorado 80217-5810; or
(ii) For courier service or overnight mail (excluding Express Mail): Minerals Management Service, Minerals Revenue Management, Building 85, Denver Federal Center, Room A-614, Denver, Colorado 80225.
[66 FR 45771, Aug. 30, 2001; 66 FR 50827, Oct. 5, 2001]
§ 210.202
How do I submit sales summaries?
(a) What to submit. (1) You must submit sales summaries for all coal and other solid minerals produced from Federal and Indian leases and for any remote storage site from which you sell Federal or Indian solid minerals. You do not have to submit a sales summary for those months in which you do not sell any Federal or Indian production.
(2) If you sell from five or fewer remote storage sites, you must submit a sales summary for each site. If you sell from more than five remote storage sites, you may total the data from all sites and submit the summarized data as one sales summary. The details you report on the sales summary are for the same sales reported on Form MMS-4430.
(3) Use the following table to determine the time frames for submitting sales summaries and the data elements you must include. Your submitted sales summaries must include the following data but may be internally generated documents from your own records. You do not need to re-format them before submitting them to us:
Data element | Coal | Sodium/potassium | Western phosphate | Metals | All other leases with ad valorem royalty terms | All other leases with no ad valorem royalty terms
(i) Purchaser Name or Unique Identification | Monthly | Monthly | Monthly | Monthly | Monthly | As Requested
(ii) Sales Units | Monthly | Monthly | Monthly | Monthly | Monthly | Monthly
(iii) Gross Proceeds | Monthly | Monthly | Not Required | Monthly | Monthly | Not Required
(iv) Processing or washing costs | Monthly | Monthly | Not Required | Monthly | Monthly | Not Required
(v) Transportation costs | Monthly | Monthly | Not Required | Monthly | Monthly | Not Required
(vi) Name of product type sold | Not Required | Monthly | Not Required | Monthly | Monthly | As Requested
(vii) Btu/lb | Monthly | Not Required | Not Required | Not Required | Not Required | Not Required
(viii) Ash % | Monthly | Not Required | Not Required | Not Required | Not Required | Not Required
(ix) Sulfur % | Monthly | Not Required | Not Required | Not Required | Not Required | Not Required
(x) lbs SO2 | Monthly | Not Required | Not Required | Not Required | Not Required | Not Required
(xi) Moisture % | Monthly | Not Required | Monthly | Not Required | Not Required | Not Required
(xii) By-product Units | Not Required | As Requested | Monthly | As Requested | As Requested | Not Required
(xiii) P2O5 % | Not Required | Not Required | Monthly | Not Required | Not Required | Not Required
(xiv) Size | Not Required | Not Required | Not Required | Not Required | As Requested | Not Required
(xv) Net Smelter Return data | Not Required | Not Required | Not Required | Monthly | Not Required | Not Required
(xvi) Other Data e.g., Royalty Calculation Worksheet | As Requested | Monthly | As Requested | As Requested | As Requested | As Requested.
(b) When to submit. (1) For leases with ad valorem royalty terms (that is, leases for which royalty is a percentage of the value of production), you must submit your sales summaries monthly at the same time you submit Form MMS-4430. You do not have to submit a sales summary for any month in which you did not sell Federal or Indian production.
(2) For leases with no ad valorem royalty terms (that is, leases in which the royalty due is not a function of the value of production, such as cents-per-ton or dollars-per-unit), you must submit monthly sales summaries only if we specifically request you to do so.
(c) How to submit. (1) You should provide the sales summary data via electronic mail where possible. We will provide instructions and the proper email address for these submissions.
(2) If you submit sales summaries by paper copy, mail them to one of the following addresses, unless MMS publishes notice in the Federal Register giving a different address:
(i) For U.S. Postal Service regular mail or Express Mail: Minerals Management Service, Minerals Revenue Management, Solid Minerals and Geothermal Compliance and Asset Management, P.O. Box 25165, MS 390G1, Denver, Colorado 80225-0165.
(ii) For courier service or overnight mail (excluding Express Mail): Minerals Management Service, Solid Minerals and Geothermal Compliance and Asset Management, 12600 West Colfax Avenue, Suite C-100, Lakewood, Colorado 80215.
§ 210.203
How do I submit sales contracts?
(a) What to submit. You must submit sales contracts, agreements, and contract amendments for the sale of all coal and other solid minerals produced from Federal and Indian leases with ad valorem royalty terms.
(b) When to submit. (1) For coal and metal production, you must submit the required documents semi-annually, no later than March 30 and September 30 of each year.
(2) For sodium, potassium, and phosphate production, and production from any other lease with ad valorem royalty terms, you must submit the required documents only if you are specifically requested to do so.
(c) How to submit. You must submit complete copies of the sales contracts and amendments to us at the applicable address given in § 210.202(c)(2), unless MMS publishes notice in the Federal Register giving a different address.
§ 210.204
How do I submit facility data?
(a) What to submit. (1) You must submit facility data if you operate a wash plant, refining, ore concentration, or other processing facility for any coal, sodium, potassium, metals, or other solid minerals produced from Federal or Indian leases with ad valorem royalty terms, regardless of whether the facility is located on or off the lease.
(2) You do not have to submit facility data for those months in which you do not process solid minerals produced from Federal or Indian leases and do not have any such minerals in stockpile inventory.
(3) You must include in your facility data all production processed in the facility from all properties, not just production from Federal and Indian leases.
(4) Facility data submissions must include the following minimum information:
(i) Identification of your facility;
(ii) Mines served;
(iii) Input quantity;
(iv) Input quality or ore grade (except for coal);
(v) Output quantity; and
(vi) Output quality or product grades.
(5) Your submitted facility data may be internally generated documents from your own records. You do not need to re-format them before submitting them to us.
(b) When to submit. You must submit your facility data monthly at the same time you submit your Form MMS-4430.
(c) How to submit. (1) You should provide the facility data via electronic mail where possible. We will provide instructions and the proper email address for these submissions before you begin reporting.
(2) If you submit facility data by paper copy, send it to the applicable address given in § 210.202(c)(2).
§ 210.205
What reports must I submit to claim allowances on Indian coal leases?
General. You must submit the following MMS forms to claim a transportation or washing allowance, as applicable, on Indian coal leases:
(1) Form MMS-4292, Coal Washing Allowance Report, to claim an allowance for the reasonable, actual costs incurred to wash coal under § 206.458 of this chapter.
(2) Form MMS-4293, Coal Transportation Allowance Report, to claim an allowance for the reasonable, actual costs of transporting coal to a sales point or a washing facility remote from the mine or lease under § 206.461 of this chapter.
(b) Reporting options. You must submit the forms manually. You may find the forms on our Internet Web site at http://www.mrm.mms.gov/ReportingServices/Forms/AFSSol_Min.htm or request forms from MMS at P.O. Box 25165, MS 390B2, Denver, Colorado 80217-0165.
(c) Reporting address. You must submit completed Forms MMS-4292 and MMS-4293 by:
(1) U.S. Postal Service regular or express mail addressed to Minerals Management Service, P.O. Box 25165, MS 390B2, Denver, Colorado 80217-0165; or
(2) Special courier or overnight mail addressed to Minerals Management Service, Building 85, Room A-614, MS 390B2, Denver Federal Center, West 6th Ave. and Kipling Blvd., Denver, Colorado 80225.
[73 FR 15897, Mar. 26, 2008]
§ 210.206
Will I need to submit additional documents or evidence to MMS?
(a) Federal and Indian lease terms allow us to request detailed statements, documents, or other evidence necessary to verify compliance with lease terms and conditions and applicable rules.
(b) We will request this additional information as we need it, not as a regular submission.
[66 FR 45771, Aug. 30, 2001. Redesignated at 73 FR 15897, Mar. 26, 2008]
§ 210.207
How will information submissions be kept confidential?
Information submitted under this part that constitutes trade secrets or commercial and financial information that is identified as privileged or confidential, or that is exempt from disclosure under the Freedom of Information Act, 5 U.S.C. 552, shall not be available for public inspection or made public or disclosed without the consent of the lessee, except as otherwise provided by law or regulation.
[66 FR 45771, Aug. 30, 2001. Redesignated at 73 FR 15897, Mar. 26, 2008]
Subpart F—Coal [Reserved]
Subpart G—Other Solid Minerals [Reserved]

Subpart H—Geothermal Resources

Source:
56 FR 57286, Nov. 8, 1991, unless otherwise noted.
§ 210.350
Definitions.
Terms used in this subpart shall have the same meaning as in 30 CFR 206.351.
§ 210.351
Required recordkeeping.
Information required by MMS shall be filed using the forms prescribed in this subpart, which are available from MMS. Records may be maintained on microfilm, microfiche, or other recorded media that are easily reproducible and readable. See subpart H of 30 CFR part 212.
§ 210.352
Special forms and reports.
The MMS may require submission of additional information on special forms or reports. When special forms or reports other than those referred to in this subpart are necessary, MMS will give instructions for the filing of such forms or reports. Requests for the submission of such forms will be made in conformity with the requirements of the Paperwork Reduction Act of 1980 and other applicable laws.
[56 FR 57286, Nov. 8, 1991. Redesignated at 72 FR 24467, May 2, 2007]
§ 210.353
Monthly report of sales and royalty.
A completed Report of Sales and Royalty Remittance (Form MMS-2014) must be submitted each month once sales or utilization of production occur, even though sales may be intermittent, unless otherwise authorized by MMS. This report is due on or before the last day of the month following the month in which production was sold or utilized, together with the royalties due the United States.
[56 FR 57286, Nov. 8, 1991. Redesignated at 72 FR 24467, May 2, 2007]
§ 210.354
Reporting instructions.
Specific guidance on how to prepare and submit required information collection reports and forms to MMS is contained in the publication titled Minerals Revenue Reporter Handbook—Oil, Gas, and Geothermal Resources, which is available from the Minerals Management Service, Minerals Revenue Management, Financial Management, P.O. Box 25165, Mail Stop 350B1, Denver, CO 80225-0165. For copies from the MMS Web site, go to http://www.mrm.mms.gov/. Click Reporting Information and select the topic.
[72 FR 24467, May 2, 2007]
Subpart I—OCS Sulfur [Reserved]
Pt. 212

PART 212—RECORDS AND FILES MAINTENANCE
Subpart A—General Provisions [Reserved]

Subpart B—Oil, Gas, and OCS Sulphur—General
Sec.
212.50
Required recordkeeping and reports.
212.51
Records and files maintenance.
212.52
Definitions.
Subpart C—Federal and Indian Oil [Reserved]
Subpart D—Federal and Indian Gas [Reserved]

Subpart E—Solid Minerals—General
212.200
Maintenance of and access to records.
Subpart F—Coal [Reserved]
Subpart G—Other Solid Minerals [Reserved]

Subpart H—Geothermal Resources
212.350
Definitions.
212.351
Required recordkeeping and reports.
Subpart I—OCS Sulfur [Reserved]

Authority:
5 U.S.C. 301 et seq.; 25 U.S.C. 396 et seq., 396a et seq., 2101 et seq.; 30 U.S.C. 181 et seq., 351 et seq., 1001 et seq., 1701 et seq.; 31 U.S.C. 9701; 43 U.S.C. 1301 et seq., 1331 et seq., and 1801 et seq.
Subpart A—General Provisions [Reserved]

Subpart B—Oil, Gas, and OCS Sulphur—General
§ 212.50
Required recordkeeping and reports.
All records pertaining to offshore and onshore Federal and Indian oil and gas leases shall be maintained by a lessee, operator, revenue payor, or other person for 6 years after the records are generated unless the recordholder is notified, in writing, that records must be maintained for a longer period. When an audit or investigation is underway, records shall be maintained until the recordholder is released by written notice of the obligation to maintain records.
[49 FR 37345, Sept. 21, 1984]
§ 212.51
Records and files maintenance.
(a) Records. Each lessee, operator, revenue payor, or other person shall make and retain accurate and complete records necessary to demonstrate that payments of rentals, royalties, net profit shares, and other payments related to offshore and onshore Federal and Indian oil and gas leases are in compliance with lease terms, regulations, and orders. Records covered by this section include those specified by lease terms, notices and orders, and by the various parts of this chapter. Records also include computer programs, automated files, and supporting systems documentation used to produce automated reports or magnetic tape submitted to the Minerals Management Service (MMS).
(b) Period for keeping records. Lessees, operators, revenue payors, or other persons required to keep records under this section shall maintain and preserve them for 6 years from the day on which the relevant transaction recorded occurred unless the Secretary notifies the record holder of an audit or investigation involving the records and that they must be maintained for a longer period. When an audit or investigation is underway, records shall be maintained until the recordholder is released in writing from the obligation to maintain the records. Lessees, operators, revenue payors, or other persons shall maintain the records generated during the period for which they have paying or operating responsibility on the lease for a period of 6 years.
(c) Inspection of records. The lessee, operator, revenue payor, or other person required to keep records shall be responsible for making the records available for inspection. Records shall be provided at a business location of the lessee, operator, revenue payor, or other person during normal business hours upon the request of any officer, employee or other party authorized by the Secretary. Lessees, operators, revenue payors, and other persons will be given a reasonable period of time to produce historical records.
[49 FR 37345, Sept. 21, 1984; 49 FR 40576, Oct. 17, 1984, as amended at 67 FR 19111, Apr. 18, 2002]
§ 212.52
Definitions.
Terms used in this subpart shall have the same meaning as in 30 U.S.C. 1702.
[49 FR 37345, Sept. 21, 1984]
Subpart C—Federal and Indian Oil [Reserved]
Subpart D—Federal and Indian Gas [Reserved]
Subpart E—Solid Minerals—General
§ 212.200
Maintenance of and access to records.
(a) All records pertaining to Federal and Indian solid minerals leases shall be maintained by a lessee, operator, revenue payor, or other person for 6 years after the records are generated unless the record holder is notified, in writing, that records must be maintained for a longer period. When an audit or investigation is underway, records shall be maintained until the record holder is released by written notice of the obligation to maintain records.
(b) The MMS shall have access to all records of the operator/lessee pertaining to compliance to Federal royalties, including, but not limited to:
(1) Qualities and quantities of all products mined, processed, sold, delivered, or used by the operator/lessee.
(2) Prices received for mined or processed products, prices paid for like or similar products, and internal transfer prices.
(3) Costs of mining, processing, handling, and transportation.
[47 FR 33193, July 30, 1982. Redesignated at 48 FR 35641, Aug. 5, 1983, and amended at 51 FR 15767, Apr. 28, 1986; 54 FR 1532, Jan. 13, 1989]
Subpart F—Coal [Reserved]
Subpart G—Other Solid Minerals [Reserved]

Subpart H—Geothermal Resources

Source:
56 FR 57286, Nov. 8, 1991, unless otherwise noted.
§ 212.350
Definitions.
Terms used in this subpart shall have the same meaning as in 30 CFR 206.351.
§ 212.351
Required recordkeeping and reports.
(a) Records. Each lessee, operator, revenue payor, or other person shall make and retain accurate and complete records necessary to demonstrate that payments of royalties, rentals, and other amounts due under Federal geothermal leases are in compliance with laws, lease terms, regulations, and orders. Records covered by this section include those specified by lease terms, notices, and orders, and those identified in paragraph (c) of this section. Records also include computer programs, automated files, and supporting systems documentation used to produce automated reports or magnetic tapes submitted to MMS.
(b) Period for keeping records. All records pertaining to Federal geothermal leases shall be maintained by a lessee, operator, revenue payor, or other person for 6 years after the records are generated unless the recordholder is notified, in writing, before the expiration of that 6-year period that records must be maintained for a longer period for purposes of audit or investigation. When an audit or investigation is underway, records shall be maintained until the recordholder is released by written notice of the obligation to maintain records.
(c) Access to records. The Associate Director for Minerals Revenue Management shall have access to all records in the possession of the lessee, operator, revenue payor, or other person pertaining to compliance with royalty obligations under Federal geothermal leases (regardless of whether such records were generated more than 6 years before a request or order to produce them and they otherwise were not disposed of), including, but not limited to:
(1) Qualities and quantities of all products extracted, processed, sold, delivered, or used by the operator/lessee;
(2) Prices received for products, prices paid for like or similar products, and internal transfer prices; and
(3) Costs of extraction, power generation, electrical transmission, and byproduct transportation.
(d) Inspection of Records. The lessee, operator, revenue payor, or other person required to keep records shall be responsible for making the records available for inspection. Records shall be made available at a business location of the lessee, operator, revenue payor, or other person during normal business hours upon the request of any officer, employee, or other party authorized by the Secretary. Lessees, operators, revenue payors, and other persons will be given a reasonable period of time to produce records.
[56 FR 57286, Nov. 8, 1991, as amended at 67 FR 19111, Apr. 18, 2002]
Subpart I—OCS Sulfur [Reserved]
PART 215—ACCOUNTING AND AUDITING STANDARDS [RESERVED]
Pt. 217

PART 217—AUDITS AND INSPECTIONS
Subpart A—General Provisions [Reserved]

Subpart B—Oil and Gas, General
Sec.
217.50
Audits of records.
217.51
Lease account reconciliation.
217.52
Definitions.
Subpart C—Oil and Gas, Onshore [Reserved]
Subpart D—Oil, Gas and Sulfur, Offshore [Reserved]

Subpart E—Coal
217.200
Audits.

Subpart F—Other Solid Minerals
217.250
Audits.

Subpart G—Geothermal Resources
217.300
Audits or review of records.
217.301
Lease account reconciliations.
217.302
Definitions.
Subpart H—Indian Lands [Reserved]

Authority:
35 Stat. 312; 35 Stat. 781, as amended; secs. 32, 6, 26, 41 Stat. 450, 753, 1248; secs. 1, 2, 3, 44 Stat. 301, as amended; secs. 6, 3, 44 Stat. 659, 710; secs. 1, 2, 3, 44 Stat. 1057; 47 Stat. 1487; 49 Stat. 1482, 1250, 1967, 2026; 52 Stat. 347; sec. 10, 53 Stat. 1196, as amended; 56 Stat. 273; sec. 10, 61 Stat. 915; sec. 3, 63 Stat. 683; 64 Stat. 311; 25 U.S.C. 396, 396a-f, 30 U.S.C. 189, 271, 281, 293, 359. Interpret or apply secs. 5, 5, 44 Stat. 302, 1058, as amended; 58 Stat. 483-485; 5 U.S.C. 301, 16 U.S.C. 508b, 30 U.S.C. 189, 192c, 271, 281, 293, 359, 43 U.S.C. 387, unless otherwise noted.
Subpart A—General Provisions [Reserved]

Subpart B—Oil and Gas, General

Authority:
The Federal Oil and Gas Royalty Management Act of 1982 (30 U.S.C. 1701 et seq.).

Source:
49 FR 37345, Sept. 21, 1984, unless otherwise noted.
§ 217.50
Audits of records.
The Secretary, or his/her authorized representative, shall initiate and conduct audits relating to the scope, nature and extent of compliance by lessees, operators, revenue payors, and other persons with rental, royalty, net profit share and other payment requirements on a Federal or Indian oil and gas lease. Audits also will relate to compliance with applicable regulations and orders. All audits will be conducted in accordance with the notice and other requirements of 30 U.S.C. 1717.
§ 217.51
Lease account reconciliation.
Specific lease account reconciliations shall be performed with priority being given to reconciling those lease accounts specifically identified by a State or Indian tribe as having significant potential for underpayment.
§ 217.52
Definitions.
Terms used in this subpart shall have the same meaning as in 30 U.S.C. 1702.
Subpart C—Oil and Gas, Onshore [Reserved]
Subpart D—Oil, Gas and Sulfur, Offshore [Reserved]

Subpart E—Coal
§ 217.200
Audits.
An audit of the accounts and books of operators/lessees for the purpose of determining compliance with Federal lease terms relating to Federal royalties may be required annually or at other times as directed by the Associate Director for Minerals Revenue Management. The audit shall be performed by a qualified independent certified public accountant or by an independent public accountant licensed by a State, territory, or insular possession of the United States or the District of Columbia, and at the expense of the operator/lessee. The operator/lessee shall furnish, free of charge, duplicate copies of audit reports that express opinions on such compliance to the Associate Director for Minerals Revenue Management within 30 days after the completion of each audit. Where such audits are required, the Associate Director for Minerals Revenue Management will specify the purpose and scope of the audit and the information which is to be verified or obtained.
[47 FR 33195, July 30, 1982. Redesignated at 48 FR 35641, Aug. 5, 1983, as amended at 67 FR 19112, Apr. 18, 2002]

Subpart F—Other Solid Minerals
§ 217.250
Audits.
An audit of the lessee's accounts and books may be made annually or at such other times as may be directed by the mining supervisor, by certified public accountants, and at the expense of the lessee. The lessee shall furnish free of cost duplicate copies of such annual or other audits to the mining supervisor, within 30 days after the completion of each auditing.
[37 FR 11041, June 1, 1972. Redesignated at 48 FR 35641, Aug. 5, 1983]

Subpart G—Geothermal Resources

Source:
72 FR 24468, May 2, 2007, unless otherwise noted.
§ 217.300
Audit or review of records.
The Secretary, or his/her authorized representative, will initiate and conduct audits or reviews relating to the scope, nature, and extent of compliance by lessees, operators, revenue payors, and other persons with rental, royalty, fees, and other payment requirements on a Federal geothermal lease. Audits or reviews will also relate to compliance with applicable regulations and orders. All audits or reviews will be conducted in accordance with this part.
§ 217.301
Lease account reconciliations.
Specific lease account reconciliations will be performed with priority being given to reconciling those lease accounts specifically identified by a State as having significant potential for underpayment.
§ 217.302
Definitions.
Terms used in this subpart will have the same meaning as in 30 U.S.C. 1702.
Subpart H—Indian Lands [Reserved]
Pt. 218

PART 218—COLLECTION OF MONIES AND PROVISION FOR GEOTHERMAL CREDITS AND INCENTIVES

Subpart A—General Provisions
Sec.
218.10
Information collection.
218.40
Assessments for incorrect or late reports and failure to report.
218.41
Assessments for failure to submit payment of same amount as Form MMS-2014 or bill document or to provide adequate information.
218.42
Cross-lease netting in calculation of late-payment interest.

Subpart B—Oil and Gas, General
218.50
Timing of payment.
218.51
How to make payments.
218.52
How does a lessee designate a Designee?
218.53
Recoupment of overpayments on Indian mineral leases.
218.54
Late payments.
218.55
Interest payments to Indians.
218.56
Definitions.

Subpart C—Oil and Gas, Onshore
218.100
Royalty and rental payments.
218.101
Royalty and rental remittance (naval petroleum reserves).
218.102
Late payment or underpayment charges.
218.103
Payments to States.
218.104
Exemption of States from certain interest and penalties.
218.105
Definitions.

Subpart D—Oil, Gas and Sulfur, Offshore
218.150
Royalties, net profit shares, and rental payments.
218.151
Rental fees.
218.152
Fishermen's Contingency Fund.
218.153
[Reserved]
218.154
Effect of suspensions on royalty and rental.
218.155
Method of payment.
218.156
Definitions.

Subpart E—Solid Minerals—General
218.200
Payment of royalties, rentals, and deferred bonuses.
218.201
Method of payment.
218.202
Late payment or underpayment charges.
218.203
Recoupment of overpayments on Indian mineral leases.

Subpart F—Geothermal Resources
218.300
Payment of royalties, rentals, and deferred bonuses.
218.301
Method of payment.
218.302
Late payment or underpayment charges.
218.303
May I credit rental towards royalty?
218.304
May I credit rental towards direct use fees?
218.305
How do I pay advanced royalties I owe under BLM regulations?
218.306
May I receive a credit against production royalties for in-kind deliveries of electricity I provide under contract to a State or county government?
218.307
How do I pay royalties due for my existing leases that qualify for near-term production incentives under BLM regulations?
Subpart G—Indian Lands [Reserved]

Subpart H—Service of Official Correspondence
218.500
What is the purpose of this subpart?
218.520
What definitions apply to this subpart?
218.540
How does MMS serve official correspondence?
218.560
How do I submit Form MMS-4444?
218.580
When do I submit Form MMS-4444?

Authority:
25 U.S.C. 396 et seq., 396a et seq., 2101 et seq.; 30 U.S.C. 181 et seq., 351 et seq., 1001 et seq., 1701 et seq.; 31 U.S.C. 3335; 43 U.S.C. 1301 et seq., 1331 et seq., and 1801 et seq.

Source:
48 FR 35641, Aug. 5, 1983, unless otherwise noted.

Subpart A—General Provisions
§ 218.10
Information collection.
The information collection requirements contained in this part have been approved by OMB under 44 U.S.C. 3501 et seq. The forms, filing date, and approved OMB clearance numbers are identified in 30 CFR 210.10.
[57 FR 41867, Sept. 14, 1992]
§ 218.40
Assessments for incorrect or late reports and failure to report.
(a) An assessment of an amount not to exceed $10 per day may be charged for each report not received by MMS by the designated due date for geothermal, solid minerals, and Indian oil and gas leases.
(b) An assessment of an amount not to exceed $10 per day may be charged for each incorrectly completed report for geothermal, solid minerals, and Indian oil and gas leases.
(c) For purpose of assessments discussed in this section, a report is defined as follows:
(1) For coal and other solid minerals leases, a report is each line on Form MMS-4430, Solid Minerals Production and Royalty Report; or on Form MMS-2014, Report of Sales and Royalty Remittance, as appropriate.
(2) For Indian oil and gas and all geothermal leases, a report is each line on Form MMS-2014.
(d) An assessment under this section shall not be shared with a State, Indian tribe, or Indian allottee.
(e) The amount of the assessment to be imposed pursuant to paragraphs (a) and (b) of this section shall be established periodically by MMS. The assessment amount for each violation will be based on MMS's experience with costs and improper reporting. The MMS will publish a Notice of the assessment amount to be applied in the Federal Register.
[49 FR 37346, Sept. 21, 1984. Redesignated and amended at 51 FR 15767, Apr. 28, 1986; 52 FR 27546, July 22, 1987; 52 FR 37452, Oct. 7, 1987; 57 FR 52720, Nov. 5, 1992; 59 FR 38906, Aug. 1, 1994; 66 FR 45773, Aug. 30, 2001; 73 FR 15897, Mar. 26, 2008]
§ 218.41
Assessments for failure to submit payment of same amount as Form MMS-2014 or bill document or to provide adequate information.
(a) The MMS may assess an amount not to exceed $250 when the amount of a payment submitted by a reporter/payor for geothermal, solid minerals, and Indian oil and gas leases is not equivalent in amount to the total of individual line items on the associated Form MMS-2014, Form MMS-4430, or a bill document, unless MMS has authorized the difference in amount.
(b) The MMS may assess an amount not to exceed $250 for each payment for geothermal, solid minerals, and Indian oil and gas leases submitted by a reporter/payor that cannot be automatically applied to the associated Form MMS-2014, Form MMS-4430, or a bill document because of inadequate or erroneous information submitted by the reporter/payor.
(c) For purposes of this section, inadequate or erroneous information is defined as:
(1) Absent or incorrect payor-assigned document number, required to be identified by the reporter/payor in Block 4 on Form MMS-2014 (document 4 number), or the reuse of the same incorrect payor-assigned document 4 number in a subsequent reporting period.
(2) Absent or incorrect bill document invoice number (to include the three-character alpha prefix and the nine-digit number) or the payor-assigned document 4 number required to be identified by the reporter/payor on the associated payment document, or the reuse of the same incorrect payor-assigned document 4 number in a subsequent reporting period.
(3) Absent or incorrect name of the administering Bureau of Indian Affairs Agency/Area office; or the word “allotted” or the tribe name on payment documents remitted to MMS for an Indian tribe or allottee. If the payment is made by EFT, the reporter/payor must identify the tribe/allottee on the EFT message by a pre-established five-digit code.
(4) Absent or incorrect MMS-assigned payor code on a payment document.
(5) Absent or incorrect identification on a payment document.
(d) For purposes of this section, the term “Form MMS-2014” includes submission of reports of royalty information, such as Form MMS-4430.
(e) For purposes of this section, a bill document is defined as any invoice that MMS has issued for assessments, late-payment interest charges, or other amount owed. A payment document is defined as a check or wire transfer message.
(f) The amount of the assessment to be imposed pursuant to paragraphs (a) and (b) of this section shall be established periodically by MMS. The assessment amount will be based on MMS' experience with costs and improper reporting and/or payment as specified in this section. The MMS will publish a Notice in the Federal Register of the assessment amount to be applied with the effective date.
[58 FR 45438, Aug. 30, 1993, as amended at 73 FR 15897, Mar. 26, 2008]
§ 218.42
Cross-lease netting in calculation of late-payment interest.
(a) Interest due from a payor on any underpayment for any Federal mineral lease or leases (onshore or offshore) and on any Indian tribal mineral lease or leases for any production month shall not be reduced by offsetting against that underpayment any overpayment made by the payor on any other lease or leases, except as provided in paragraph (b) of this section. Interest due from a payor or any underpayment on any Indian allotted lease shall not be reduced by offsetting against any overpayment on any other Indian allotted lease under any circumstances.
(b) Royalties attributed to production from a lease or leases which should have been attributed to production from a different lease or leases may be offset to determine whether and to what extent an underpayment exists on which interest is due if the following conditions are met:
(1) The error results from attributing and reporting an equal volume of production, produced from a lease or leases during a particular production month, to a different lease or leases from which it was not produced for the same or another production month;
(2) The payor is the same for the lease or leases to which production was attributed and the lease or leases to which it should have been attributed;
(3) The payor submits production reports, pipeline allocation reports, or other similar documentary evidence pertaining to the specific production involved which verifies the correct production information;
(4) The lessor is the same for the leases involved (in the case of Indian tribal leases, the same tribe is the lessor); and
(5) The ultimate recipients of any royalty or other lease revenues under any applicable permanent indefinite appropriations are the same for, and receive the same percentage of revenue from, the leases.
(c) If MMS assesses late-payment interest and the payor asserts that some or all of the interest assessed is not owed pursuant to the exception set forth in paragraph (b) of this section, the burden is on the payor to demonstrate that the exception applies in the specific circumstances of the case.
(d) The exception set forth in paragraph (b) of this section shall not operate to relieve any payor of liability imposed by statute or regulation for erroneous reporting.
[57 FR 62206, Dec. 30, 1992]

Subpart B—Oil and Gas, General

Source:
49 FR 37346, Sept. 21, 1984, unless otherwise noted.
§ 218.50
Timing of payment.
(a) Royalty payments are due at the end of the month following the month during which the oil and gas is produced and sold except when the last day of the month falls on a weekend or holiday. In such cases, payments are due on the first business day of the succeeding month. Rental payments are due as specified by the lease terms.
(b) Invoices will be issued and payable as final collection actions. Payments made on an invoice are due as specified by the invoice.
(c) All payments to MMS are due as specified and are not deferred or suspended by reason of an appeal having been filed unless such deferral or suspension is approved in writing by an authorized MMS official.
(d)(1) Notwithstanding the provisions of paragraph (a) of this section and corresponding lease terms and 30 CFR 210.52, the due date for submittal of royalty payments and Reports of Sales and Royalty Remittance (Form MMS-2014) for the production months of July, August, September, and October 2005 for Federal offshore and onshore oil and gas leases by oil and gas lessees or royalty payors who make the certification required under paragraph (d)(2) of this section is extended until January 3, 2006.
(2) The extended due dates in paragraph (d)(1) of this section will apply to royalty payments and Reports of Sales and Royalty Remittance (Form MMS-2014) by any lessee or royalty payor who certifies that a hurricane that struck the Gulf of Mexico coast of the United States in August or September 2005 disrupted the lessee's or payor's operations to the extent that it prevented the lessee or royalty payor from making an accurate royalty payment or submitting an accurate Form MMS-2014.
(3) A lessee's or royalty payor's certification under paragraph (d)(2) of this section that it is unable to generate and submit either an accurate royalty report or an accurate royalty payment will extend the due date for both royalty reporting and royalty payment.
(4) Paragraphs (d)(1) through (d)(3) of this section do not apply to Indian leases or to Federal leases for minerals other than oil and gas.
(5) Certifications under paragraph (d)(2) of this section should be submitted either:
(i) By mail to: Robert Prael, Financial Manager, Minerals Management Service, Minerals Revenue Management, P.O. Box 25165, MS 350B1, Denver, CO 80225-0165, or
(ii) By e-mail to Robert.Prael@mms.gov.
(e)(1) A lessee or royalty payor who submits a certification required under paragraph (d)(2) of this section may rely on the extended due dates prescribed in paragraph (d)(1) of this section unless and until MMS notifies the lessee or royalty payor or operator that MMS does not accept the certification.
(2) If MMS notifies the lessee or royalty payor that MMS does not accept the lessee's or royalty payor's certification under paragraph (d)(2) of this section, the due date for royalty payments and Reports of Sales and Royalty Remittance will be the date specified in the notice.
[49 FR 37346, Sept. 21, 1984, as amended at 70 FR 56853, Sept. 29, 2005; 73 FR 15898, Mar. 26, 2008]
§ 218.51
How to make payments.
(a) Definitions.
ACH—Automated Clearing House. A type of EFT using the ACH network.
Courtesy Notice—An MMS-issued notice of rental or bonus due.
Deferred Bonus Payment—Lease bonus paid in equal annual installments over a specified number of years.
EFT—Electronic Funds Transfer. Any paperless transfer of funds a bank initiates through an electronic terminal. For MMS purposes, EFT is limited to FEDWIRE and ACH transfers.
FEDWIRE—A type of EFT using the Federal Reserve Wire network.
Invoice document identification—The MMS-assigned invoice document identification (three-alpha and nine-numeric characters).
Payment—Any monies for royalty, bonus, rental, late payment charge, assessment, penalty, or other money sent to MMS.
Person—Any individual, firm, corporation, association, partnership, consortium, or joint venture (when established as a separate entity). The term does not include Federal agencies.
Report—Form MMS-2014, Report of Sales and Royalty Remittance.
RIK—Royalty in kind.
(b) General instructions. You must make all payments to MMS electronically to the extent it is cost effective and practical. If you pay money to MMS or to an Indian tribe or allottee, you must follow these procedures:
(1) If MMS instructs you to use EFT, you must use EFT for all payments to MMS and/or a tribe.
(2) Contact MMS before using EFT. MMS will provide you with EFT payment instructions.
(3) Separate any payments on a Federal lease from any payments on an Indian lease.
(4) If you are not required to use EFT, use one of the following types of payment documents. MMS prefers that you use these payment documents in the order presented:
(i) Commercial check drawn on a solvent bank;
(ii) Certified check;
(iii) Cashier's check;
(iv) Money order;
(v) Bank draft drawn on a solvent bank; or
(vi) Federal Reserve check.
(5) You must include your payor code on all payments.
(6) You must pay in U.S. dollars.
(c) How to complete a non-EFT payment. (1) Make any payment on a Federal lease payable to: “Department of the Interior-Minerals Management Service” or “DOI-MMS.”
(2) For an Indian allottee payment, send a separate payment for each Bureau of Indian Affairs (BIA) agency or area office represented by the leases on your report or invoice document. You must include the name of the applicable BIA agency or area office on your payment. Make your payment document payable to: “Department of the Interior-Minerals Management Service for BIA [Name] Agency (allotted)” or “DOI-MMS for BIA [Name] Agency (allotted).”
(3) For an Indian tribal payment other than a lockbox payment, send a separate payment for each tribe represented by the leases on your report or invoice document. You must include the name of the Indian tribe on your payment. Make it payable to: “Department of the Interior-Minerals Management Service for BIA [Name of Tribe]” or “DOI-MMS for BIA [Name of Tribe].”
(4) For an Indian tribal lockbox payment, follow the instructions MMS provides you on how to report and make the lockbox payment. These instructions are specific to each tribe's lockbox written agreement with the bank authorized to receive payments on the tribe's mineral leases. You will receive these instructions from MMS when you are required to use a tribal lockbox for reports and payments.
(d) Where to send a non-EFT payment when you use the U.S. Postal Service. (1) For a payment to an Indian tribal lockbox, send your payment to the appropriate tribal lockbox address.
(2) For a Federal nonproducing lease rental or deferred bonus payment, send it to:
Minerals Management Service, Minerals Revenue Management, P.O. Box 5640, Denver, CO 80217-5640.
(3) For all other Federal and Indian lease payments other than those going to an Indian tribal lockbox, send them to:
Minerals Management Service, Minerals Revenue Management, P.O. Box 5810, Denver, CO 80217-5810.
(e) Where to send a non-EFT payment when you use a courier or overnight delivery service. You should send this type of payment to:
Minerals Management Service, Minerals Revenue Management, Building 85, Denver Federal Center, Room A-614, Denver, CO 80225-0165.
(f) How to prepare and what to include on your payment document. (1) For Form MMS-2014 payments, you must include both your payor code and your payor-assigned document number.
(2) For invoice payments, including RIK invoice payments, you must include both your payor code and invoice document identification.
(3) For bonus payments:
(i) For one-fifth bonus payments for offshore oil, gas, and sulphur leases, follow the instructions in the Notice of Lease Offering.
(ii) For payment of the four-fifths bonus for an offshore lease, use EFT and follow the instructions in § 218.155(c).
(iii) For the successful bidder's bonus in the competitive sale of a coal, geothermal, or offshore mineral (other than oil, gas or sulfur) lease, follow the instructions and terms of the Notice of Competitive Lease Sale.
(iv) For installment payments of deferred bonuses, you must use EFT.
(4) If you are paying a lease rental you must:
(i) See 30 CFR 218.155(c) for instructions on how to pay first-year rentals of an offshore oil, gas, or sulfur lease;
(ii) See the Notice of Lease Offering for instructions on how to pay first-year rentals other than those covered in paragraph (f)(4)(i) of this section.
(iii) Include the MMS Courtesy Notice, when provided, or write your payor code and government-assigned lease number on the payment document when paying a rental that is not reported on Form MMS-2014 and not paid by EFT.
(g) When is a payment to MMS due? (1) All payments are due to MMS at the time law, regulation, or lease terms require unless MMS approves a change according to part 243 of this chapter. If you file an appeal, and the requirement to submit payment is suspended, the original payment due date for purposes such as calculating late payment interest is not changed.
(2) If you use the U.S. Postal Service, courier, or overnight mail to send your payment, it is due at the MMS addresses in paragraphs (d) and (e) of this section before 4 p.m. Mountain Time on the due date, regardless of when you sent it.
(3) If you use EFT to send your payment, it is due in the MMS account by the payment due date. You are responsible for your actions or your bank's actions that cause a late or incorrect payment. You will not be held responsible for mechanical or system failures of EFT payments.
(h) What happens if payments are late or overdue? (1) If MMS receives your payment late, MMS will impose a late-payment interest charge under 30 CFR 218.54.
(2) If you do not pay an amount you owe, MMS may assess civil penalties under part 241 of this chapter or other applicable regulations.
[62 FR 19498, Apr. 22, 1997, as amended at 66 FR 45773, Aug. 30, 2001; 67 FR 19112, Apr. 18, 2002; 73 FR 15898, Mar. 26, 2008]
§ 218.52
How does a lessee designate a Designee?
(a) If you are a lessee under 30 U.S.C. 1702(7), and you want to designate a person to make all or part of the payments due under a lease on your behalf under 30 U.S.C. 1712(a), you must notify MMS or the applicable delegated state in writing of such designation by submitting Form MMS-4425, Designation Form for Royalty Payment Responsibility. Your notification for each lease must include the following:
(1) The lease number for the lease;
(2) The type of products you make payments for e.g., oil, gas.
(3) The type of payments you are responsible for e.g., royalty, minimum royalty, rental.
(4) Whether you are:
(i) A lessee of record (record title owner) in the lease; or
(ii) An operating rights owner (working interest owner) in the lease, and the percentage of your operating rights ownership in the lease;
(5) The name, address, Taxpayer Identification Number (TIN), and phone number of your Designee;
(6) The name, address, and phone number of the individual to contact for the person you named in paragraph (a)(5) of this section;
(7) Your TIN;
(8) The date the designation is effective;
(9) The date the designation terminates, if applicable, and
(10) A copy of the written designation;
(b) The person you designate under paragraph (a) of this section is your Designee under 30 U.S.C. 1701(24) and 30 U.S.C. 1712(a).
(c) If you want to terminate a designation you made under paragraph (a) of this section, you must submit a revised Form MMS-4425 before the termination stating:
(1) The date the designation is due to terminate; and
(2) If you are not reporting and paying royalties and making other payments to MMS, a new designation under paragraph (a) of this section.
(d) MMS may require you to provide notice when there is a change in the percentage of your record title or operating rights ownership.
[62 FR 42066, Aug. 5, 1997, as amended at 73 FR 15898, Mar. 26, 2008]
§ 218.53
Recoupment of overpayments on Indian mineral leases.
(a) Whenever an overpayment is made under an Indian oil and gas lease, a payor may recoup the overpayment through a recoupment on Form MMS-2014 against the current month's royalties or other revenues owed on the same lease. However, for any month a payor may not recoup more than 50 percent of the royalties or other revenues owed in that month under an individual allotted lease or more than 100 percent of the royalties or other revenues owed in that month under a tribal lease.
(b) With written permission authorized by tribal statute or resolution, a payor may recoup an overpayment against royalties or other revenues owed in that month under other leases for which that tribe is the lessor. A copy of the tribe's written permission must be furnished to MMS pursuant to instructions for reporting recoupments in the MMS revenue reporter handbook. See part 210 of this chapter. Recouping overpayments on one allotted lease from royalties paid to another allotted lease is specifically prohibited.
(c) Overpayments subject to recoupment under this section include all payments made in excess of the required payment for royalty, rental, bonus, or other amounts owed as specified by statute, regulation, order, or terms of an Indian mineral lease.
(d) The MMS Director or his/her designee may order any payor to not recoup any amount for such reasonable period of time as may be necessary for MMS to review the nature and amount of any claimed overpayment.
[60 FR 3087, Jan. 13, 1995, as amended at 67 FR 19112, Apr. 18, 2002]
§ 218.54
Late payments.
(a) An interest charge shall be assessed on unpaid and underpaid amounts from the date the amounts are due.
(b) The interest charge on late payments shall be at the underpayment rate established by the Internal Revenue Code, 26 U.S.C. 6621(a)(2) (Supp. 1987).
(c) Interest will be charged only on the amount of the payment not received. Interest will be charged only for the number of days the payment is late.
(d) A portion of the interest collected will be paid to a State where the State shares in mineral revenues from Federal leases.
(e) An overpayment on a lease or leases may be offset against an underpayment on a different lease or leases to determine a net underpayment on which interest is due pursuant to conditions specified in § 218.42.
[49 FR 37346, Sept. 21, 1984, as amended at 55 FR 37230, Sept. 10, 1990; 57 FR 62206, Dec. 30, 1992]
§ 218.55
Interest payments to Indians.
(a) All interest collected from unpaid or underpayments on Indian tribal or allotted leases will be paid to the tribe or allottee.
(b) Any disbursement of Indian mineral revenues not made by the due date as required in § 219.103 of this chapter shall accrue interest.
(c) Interest shall be computed at the underpayment rate established by the Internal Revenue Code, 26 U.S.C. 6621(a)(2) (Supp. 1987).
(d) The interest shall be payable only for the number of days the disbursement is late.
[49 FR 37346, Sept. 21, 1984, as amended at 55 FR 37230, Sept. 10, 1990]
§ 218.56
Definitions.
Terms used in this subpart shall have the same meaning as in 30 U.S.C. 1702.
[49 FR 37346, Sept. 21, 1984. Redesignated at 51 FR 15767, Apr. 28, 1986]

Subpart C—Oil and Gas, Onshore
§ 218.100
Royalty and rental payments.
(a) Payment of royalties and rentals. As specified under the provisions of the lease, the lessee shall submit all rental payments when due and shall pay in value or deliver in production all royalties in the amounts of value or production determined by MMS to be due.
(b) If the lessor elects to take royalty in oil or gas, unless otherwise agreed upon, such royalty shall be delivered on the leasehold, by the lessee to the order of and without cost to the lessor, as instructed by the Associate Director.
(c) Method of payment. The payor shall tender all payments in accordance with 30 CFR 218.51.
[47 FR 47773, Oct. 27, 1982. Redesignated at 48 FR 35641, Aug. 5, 1983, and amended at 52 FR 23815, June 25, 1987]
§ 218.101
Royalty and rental remittance (naval petroleum reserves).
Remittance covering payments of royalty or rental on naval petroleum reserves must be accomplished by necessary identification information and sent direct to the Director, Naval Petroleum Reserves in California.
[47 FR 47773, Oct. 27, 1982. Redesignated at 48 FR 35641, Aug. 5, 1983]
§ 218.102
Late payment or underpayment charges.
(a) The failure to make timely or proper payments of any monies due pursuant to leases, permits, and contracts subject to these regulations will result in the collection by the MMS of the full amount past due plus a late payment charge. Exceptions to this late payment charge may be granted when estimated payments on minerals production have already been made timely and otherwise in accordance with instructions provided by MMS to the payor. However, late payment charges assessed with respect to any Indian lease, permit, or contract shall be collected and paid to the Indian or tribe to which the amount overdue is owed.
(b) Late payment charges will be assessed on any late payment or underpayment from the date that the payment was due until the date that the payment was received at the MMS addresses specified in § 218.51. Payments received at the specified MMS addresses after 4 p.m. mountain time are considered received the following business day.
(c) Late payment charges apply to all underpayments and payments received after the date due. The charges include production and minimum royalties; assessments for liquidated damages; administrative fees and payments by purchasers of royalty taken-in-kind; or any other payments, fees, or assessments that a lessee/operator/permittee/payor/royalty taken-in-kind purchaser is required to pay by a specified date. The failure to pay past due amounts, including late-payment charges, will result in the initiation of other enforcement proceedings.
(d) An overpayment on a lease or leases may be offset against an underpayment on a different lease or leases to determine a net underpayment on which interest is due pursuant to conditions specified in § 218.42.
[47 FR 47773, Oct. 27, 1982. Redesignated at 48 FR 35641, Aug. 5, 1983, and amended at 49 FR 37347, Sept. 21, 1984; 57 FR 41868, Sept. 14, 1992; 57 FR 62206, Dec. 30, 1992; 67 FR 19112, Apr. 18, 2002]
§ 218.103
Payments to States.
(a) Any amount that is payable by MMS to a State but is not paid on the due date, as specified in § 219.100 of this chapter, or that is held in a suspense account pending resolution of a dispute as specified in § 219.101 of this chapter, shall accrue interest payable to the State.
(b) Interest shall be computed at the underpayment rate established by the Internal Revenue Code, 26 U.S.C. 6621(a)(2) (Supp. 1987).
(c) Interest shall be computed only for the number of days the disbursement is late. In the case of suspended amounts subject to interest, it shall be computed beginning with the calendar day following the day that the monies normally would have been paid to the State had they not been in suspense.
[49 FR 37347, Sept. 21, 1984, as amended at 55 FR 37230, Sept. 10, 1990]
§ 218.104
Exemption of States from certain interest and penalties.
(a) States are exempt from being assessed for any interest or penalties found to be due against the Department of the Interior for failure to comply with the Emergency Petroleum Allocation Act of 1973, as amended, or any regulation issued by the Secretary of Energy thereunder concerning the certification or processing of crude oil taken in-kind as royalty by the Secretary.
(b) Any State shall be assessed for its share of any overcharge resulting from a determination that DOI failed to comply with the Emergency Petroleum Allocation Act of 1973, as amended. Each State's share shall be assessed against monies owed to the State. Such assessment shall be first against monies owed to such State as a result of royalty audits prior to January 12, 1983, the enactment date of the Federal Oil and Gas Royalty Management Act of 1982, then against other monies owed. The State shall be liable for any balance.
(c) A State's liability for repayment of an overcharge under this section shall exist for any amounts resulting from a judgment in a civil suit or as the result of settlement of a claim through a negotiated agreement. State liability would be offset against future mineral revenue distributions to the State.
[49 FR 37347, Sept. 21, 1984]
§ 218.105
Definitions.
Terms used in this subpart have the same meaning as in 30 U.S.C. 1702.
[49 FR 37347, Sept. 21, 1984]

Subpart D—Oil, Gas and Sulfur, Offshore
§ 218.150
Royalties, net profit shares, and rental payments.
(a) As specified under the provisions of the lease, the lessee shall submit all rental payments when due and shall pay in value or deliver in production all royalties and net profit shares in the amounts of value or production determined by MMS to be due.
(b) The failure to make timely or proper payments of any monies due pursuant to leases, permits, and contracts subject to these regulations will result in the collection of the amount past due plus a late payment charge. Exceptions to this late payment charge may be granted when estimated payments on minerals production have already been made timely and otherwise in accordance with instructions provided by MMS to the payor.
(c) Late payment charges will be assessed on any late payment or underpayment from the date that the payment was due until the date that the payment was received at the MMS addresses specified in § 218.51. Payments received at the specified MMS addresses after 4 p.m. mountain time are considered received the following business day.
(d) Late payment charges apply to all underpayments and payments received after the date due. These charges include production and minimum royalties; assessments for liquidated damages; administrative fees and payments by purchasers of royalty taken-in-kind; or any other payments, fees, or assessments that a lessee/operator/payor/permittee/royalty taken-in-kind purchaser is required to pay by a specified date. The failure to pay past due amounts, including late payment charges, will result in the initiation of other enforcement proceedings.
(e) An overpayment on a lease or leases, excluding rental payments, may be offset against an underpayment on a different lease or leases to determine a net underpayment on which interest is due pursuant to conditions specified in § 218.42.
[47 FR 22528, May 25, 1982. Redesignated at 48 FR 35641, Aug. 5, 1983, and amended at 49 FR 37347, Sept. 21, 1984; 52 FR 23815, June 25, 1987; 57 FR 41868, Sept. 14, 1992; 57 FR 62206, Dec. 30, 1992; 67 FR 19112, Apr. 18, 2002]
§ 218.151
Rental fees.
The annual rental paid in any year is in addition to, and is not credited against, any royalties due from production. The lessee must pay an annual rental as shown in paragraphs (a), (b), and (c) of this section. Discovery means one or more wells on the lease that meet the requirements in 250, subpart A of this title.
(a) This paragraph applies to any lease not covered by paragraph (b) or paragraph (c) of this section.
For— | Issued as a result of a sale held— | The lessee must pay rental—
(1) An oil and gas lease | Before March 26, 2001 | On or before the first day of each lease year before the discovery of oil or gas on the lease.
(2) An oil and gas lease | After March 26, 2001 | On or before the first day of each lease year before the discovery of oil or gas on the lease, then on or before the last day of each lease year in any full year in which royalties on production are not due.
(3) A mineral lease for other than oil or gas | Before March 26, 2001 | On or before the first day of each lease year before the discovery of paying quantities.
(4) A mineral lease for other than oil or gas | After March 26, 2001 | On or before the first day of each lease year before the date the first royalty payment is due on the lease, then on or before the last day of each lease year in any full year in which royalties on production are not due.
(b) This paragraph applies to any lease created by segregating a portion of a producing lease when there is no actual or allocated production on the segregated portion. The lessee must pay an annual rental for the segregated portion at the rate specified in the lease. The lessee must pay the rental as shown in the following table.
If the lease results from a segregation— | The lessee must pay rental—
(1) Before March 26, 2001 | On or before the first day of each lease year before the discovery of oil or gas on the segregated portion.
| (2) After March 26, 2001 | On or before the first day of each lease year before the discovery of oil or gas on the lease, then on or before the last day of each lease year in any full year in which royalties on production are not due.
(c) For leases issued subject to the net profit sharing provisions, annual rental payments shall be due and payable in advance, on the first day of each lease year which commences prior to the date the first profit share payment becomes due. The owner of any lease created by the segregation of a portion of a lease subject to net profit sharing provisions, shall pay an annual rental for such segregated portion at the rate per acre or hectare specified in the lease. This rental shall be payable each year following the year in which the segregation becomes effective and shall continue to be due and payable, in advance, on the first day of each year which commences prior to the date the first profit share payment becomes due.
[44 FR 38276, June 29, 1979, as amended at 45 FR 69175, Oct. 17, 1980; 47 FR 25972, June 16, 1982. Redesignated at 47 FR 47006, Oct. 22, 1982, and at 48 FR 35641, Aug. 5, 1983; 66 FR 11518, Feb. 23, 2001; 67 FR 19112, Apr. 18, 2002]
§ 218.152
Fishermen's Contingency Fund.
Upon the establishment of the Fishermen's Contingency Fund, any holder of a lease issued or maintained under the Outer Continental Shelf Lands Act and any holder of an exploration permit or of an easement or right-of-way for the construction of a pipeline, shall pay an amount specified by the Director, MMS, who shall assess and collect the specified amount from each holder and deposit it into the Fund. With respect to prelease exploratory drilling permits, the amount will be collected at the time of issuance of the permit.
[52 FR 5458, Feb. 23, 1987]
§ 218.153
[Reserved]
§ 218.154
Effect of suspensions on royalty and rental.
(a) MMS will not relieve the lessee of the obligation to pay rental or minimum royalty for or during the suspension if the Regional Supervisor:
(1) Grants a suspension of operations or production, or both, at the request of the lessee; or
(2) Directs a suspension of operations or production, or both, under 30 CFR 250.173(a).
(b) MMS will not require a lessee to pay rental or minimum royalty for or during the suspension if the Regional Supervisor directs a suspension of operations or production, or both, except as provided in (a)(2) of this section.
(c) If the lease anniversary date falls within a period of suspension for which no rental or minimum royalty payments are required under paragraph (b) of this section, the prorated rentals or minimum royalties are due and payable as of the date the suspension period terminates. These amounts shall be computed and notice thereof given the lessee. The lessee shall pay the amount due within 30 days after receipt of such notice. The anniversary date of a lease shall not change by reason of any period of lease suspension or rental or royalty relief resulting therefrom.
[44 FR 38276, June 29, 1979; 44 FR 55380, Sept. 26, 1979. Redesignated and amended at 47 FR 47006, 47007, Oct. 22, 1982. Further redesignated at 48 FR 35641, Aug. 5, 1983 and amended at 51 FR 19063, May 27, 1986; 54 FR 50616, Dec. 8, 1989; 64 FR 72775, Dec. 28, 1999; 73 FR 15898, Mar. 26, 2008]
§ 218.155
Method of payment.
(a) Payment of royalties and rentals. With the exception of first-year rental, the payor shall tender all payments in accordance with § 218.51. First-year rental shall be paid in accordance with paragraph (c) of this section.
(b) Payment of the one-fifth bonus bid amount. (1) Each lease bid must include a payment for the one-fifth bonus bid deposit amount unless the bidder is otherwise directed by the Secretary. Further instructions on how to make payment with the bid will be included in the notice of each lease offering. EFT may be used as a method of payment for the one-fifth bonus bid amount.
(2) Beginning with lease offerings held after February 1, 1984, the one-fifth bonus amount received from a high bidder shall be deposited into an escrow account created pursuant to an agreement between the Departments of the Interior and Treasury, pending acceptance or rejection of the bid. The one-fifth bonus funds will be invested in public debt securities. Investment of this amount by the U.S. Government does not indicate acceptance of the bid. The one-fifth bonus amounts submitted with bids other than the highest valid bid will be returned to respective bidders after bids are opened, recorded, and ranked. Return of such amounts will not affect the status, validity, or ranking of bids. The one-fifth bonus bid amount received from any high bidder and held by the Government pending acceptance or rejection, will be returned with actual interest earned, if the bid is subsequently rejected. The interest accrued during the period held in the account pending acceptance or rejection of the bid will accrue to the Government when the bid is accepted.
(c) Payment of the four-fifths bonus bid amount and the first year's rental. Payment shall be made to MMS by EFT unless otherwise directed by the Secretary. The payment by EFT via the FRCS must be received by the Federal Reserve Bank of New York no later than noon, eastern standard time, on the 11th business day after receipt of the lease forms by the successful bidder. A “business day” is considered to be a day on which the OCS regional office issuing the lease is open for business. The lease will not be executed by the appropriate MMS official until payment is received. Failure to remit by EFT or as directed by the Secretary within the time specified above will result in forfeiture of the one-fifth bonus bid amount and the lease will not be executed by the appropriate MMS official. Payors will not be held responsible for late payment due to actions beyond their control, such as mechanical or systems failure of FRCS or FDS. Payors will be held responsible for incorrect actions of their bank which result in late payments. A 2-day grace period will be allowed to make up a deficient payment, but a late payment charge will be assessed for this late payment and a penalty will also be assessed if appropriate. Late payment charges will be assessed in accordance with Subpart B of this part.
(d) General. (1) Payors using the appropriate means of payment (EFT, check, etc.) may pay for multiple lease obligations with a single remittance but must ensure that the payment complies with subpart B of this part and the remittance advice adequately identifies the single payment. The format to be used for such identification will be provided by the MMS Accounting Center.
(2) Where to pay.
(3) The MMS mailing addresses for payments to MMS are specified in § 218.51.
(4) Payments received at the MMS addresses after 4 p.m. mountain time are considered received the following business day.
(e) Miscellaneous payments. Payments shall be made to the manager of the appropriate Outer Continental Shelf field office by cash, check or bank draft payable to “Department of the Interior—MMS” for miscellaneous payments such as:
(1) Pipeline rights-of-way application filing fees and rentals, pipeline accessory site rentals and application fees, and other related costs.
(2) Filing and approval fees for transfers of interest in leases.
[49 FR 8605, Mar. 8, 1984, as amended at 52 FR 23815, June 25, 1987; 53 FR 43201, Oct. 26, 1988; 57 FR 41868, Sept. 14, 1992; 62 FR 19499, Apr. 22, 1997; 67 FR 19112, Apr. 18, 2002; 73 FR 15898, Mar. 26, 2008]
§ 218.156
Definitions.
Terms used in this subpart have the same meaning as in 30 U.S.C. 1702.
[52 FR 23815, June 25, 1987]

Subpart E—Solid Minerals—General
§ 218.200
Payment of royalties, rentals, and deferred bonuses.
As specified under the provisions of the lease, the lessee shall submit all rental and deferred bonus payments when due and shall pay in value all royalties in the amount determined by MMS to be due.
[52 FR 23815, June 25, 1987]
§ 218.201
Method of payment.
You must tender all payments in accordance with § 218.51, except as follows:
(a) For purposes of this section, report means the Solid Minerals Production and Royalty Report, Form MMS-4430, rather than the Form MMS-2014.
(b) For Form MMS-4430 payments, include both your customer identification and your customer document identification numbers on your payment document, rather than the information required under § 218.51(f)(1).
(c) For a rental payment that is not reported on Form MMS-4430, include the MMS Courtesy Notice when provided or write your customer identification number and Government-assigned lease number on the payment document, rather than the information required under § 218.51(f)(4)(iii).
[66 FR 45773, Aug. 30, 2001]
§ 218.202
Late payment or underpayment charges.
(a) The failure to make timely or proper payment of any monies due pursuant to leases and contracts subject to these rules will result in the collection by MMS of the full amount past due plus a late payment charge. Exceptions to this late payment charge may be granted when estimated payments on minerals production have already been made timely and otherwise in accordance with instructions provided by MMS to the operator/lessee. However, late payment charges assessed with respect to any Indian lease, permit, or contract shall be collected and paid to the Indian or tribe to which the amount overdue is owed.
(b) Late payment charges will be assessed on any late payment or underpayment from the date that the payment was due until the date that the payment was received at the MMS addresses specified in § 218.51. Payments received at the specified MMS addresses after 4 p.m. mountain time are considered received the following business day.
(c) Late payment charges are calculated on the basis of a percentage assessment rate. In the absence of a specific lease, permit, license or contract provision prescribing a different rate, this percentage assessment rate is prescribed by the Department of the Treasury as the “Treasury Current Value of Funds Rate.”
(d) This rate is available in the Treasury Fiscal Requirements Manual Bulletins that are published prior to the first day of each calendar quarter for application to overdue payments or underpayments in the new calendar quarter. The rate is also published in the Notices section of the Federal Register and indexed under “Fiscal Service/Notices/Funds Rate; Treasury Current Value.”
(e) Late payment charges apply to all underpayments and payments received after the date due. These charges include production, minimum, or advance royalties; assessments for liquidated damages; or any other payments, fees, or assessments that an operator/lessee is required to pay by a specified date. The failure to pay past due payments, including late payment charges, will result in the initiation of other enforcement proceedings.
(f) An overpayment on a lease or leases may be offset against an underpayment on a different lease or leases to determine a net underpayment on which interest is due pursuant to conditions specified in § 218.42.
[47 FR 33195, July 30, 1982; 47 FR 53366, Nov. 26, 1982. Redesignated at 48 FR 35641, Aug. 5, 1983, and further redesignated at 52 FR 23815, June 25, 1987, as amended at 57 FR 41868, Sept. 14, 1992; 57 FR 62207, Dec. 30, 1992; 59 FR 14559, Mar. 29, 1994; 65 FR 55189, Sept. 13, 2000; 67 FR 19112, Apr. 18, 2002]
§ 218.203
Recoupment of overpayments on Indian mineral leases.
(a) Whenever an overpayment is made under an Indian solid mineral lease, a payor may recoup the overpayment through a recoupment on Form MMS-4430 against the current month's royalties or other revenues owed on the same lease. However, for any month a payor may not recoup more than 50 percent of the royalties or other revenues owed in that month under an individual allotted lease or more than 100 percent of the royalties or other revenues owed in that month under a tribal lease.
(b) With written permission authorized by tribal statute or resolution, a payor may recoup an overpayment against royalties or other revenues owed in that month under other leases for which that tribe is the lessor. A copy of the tribe's written permission must be furnished to MMS for reporting recoupments. Call 1-888-201-6416 for instructions. Recouping overpayments on one allotted lease from royalties paid to another allotted lease is specifically prohibited.
(c) Overpayments subject to recoupment under this section include all payments made in excess of the required payment for royalty, rental, bonus, or other amounts owed as specified by statute, regulation, order, or terms of an Indian mineral lease.
(d) The MMS Director or his/her designee may order any payor to not recoup any amount for such reasonable period of time as may be necessary for MMS to review the nature and amount of any claimed overpayment.
[60 FR 3087, Jan. 13, 1995, as amended at 66 FR 45773, Aug. 30, 2001; 66 FR 50827, Oct. 5, 2001]

Subpart F—Geothermal Resources
§ 218.300
Payment of royalties, rentals, and deferred bonuses.
As specified under the provisions of the lease, the lessee shall submit all rental and deferred bonus payments when due and shall pay in value all royalties in the amount determined by MMS to be due.
[52 FR 23815, June 25, 1987]
§ 218.301
Method of payment.
The payor shall tender all payments in accordance with 30 CFR 218.51.
[52 FR 23815, June 25, 1987]
§ 218.302
Late payment or underpayment charges.
(a) The failure to make timely or proper payment of any monies due pursuant to leases and contracts subject to these regulations will result in the collection by the Minerals Management Service (MMS) of the full amount past due plus a late payment charge. Exceptions to this late payment charge may be granted when estimated payments on minerals production have already been made timely and otherwise in accordance with the instructions provided by the MMS to the payor.
(b) Late payment charges will be assessed on any late payment or underpayment from the date that the payment was due until the date that the payment was received at the MMS addresses specified in § 218.51. Payments received at the specified MMS addresses after 4 p.m. Mountain Time are considered received the following business day.
(c) Late payment charges are calculated on the basis of a percentage assessment rate. In the absence of a specific lease, permit, license or contract provision prescribing a different rate, this percentage assessment rate is prescribed by the Department of the Treasury as the “Treasury Current Value of Funds Rate.”
(d) This rate is available in the Treasury Fiscal Requirements Manual Bulletins that are published prior to the first day of each calendar quarter for application to overdue payments or underpayments in the new calendar quarter. The rate is also published in the Notices section of the Federal Register and indexed under “Fiscal Service/Notices/Funds Rate; Treasury Current Value.”
(e) Late payment charges apply to all underpayments and payments received after the date due. These charges include production, minimum, and compensatory royalties; assessments for liquidated damages; administrative fees and payments by purchasers of royalty taken-in-kind; or any other payments, fees, or assessments that a lessee/operator/payor/royalty taken-in-kind purchaser is required to pay by a specified date. The failure to pay past due payments, including late payment charges, will result in the initiation of other enforcement proceedings.
(f) An overpayment on a lease or leases may be offset against an underpayment on a different lease or leases to determine a net underpayment on which interest is due pursuant to conditions specified in § 218.42.
[47 FR 22528, May 25, 1982. Redesignated at 48 FR 35641, Aug. 5, 1983, and further redesignated at 51 FR 15767, Apr. 28, 1986 and 52 FR 23815, June 25, 1987, as amended at 57 FR 41868, Sept. 14, 1992; 57 FR 62207, Dec. 30, 1992; 59 FR 14559, Mar. 29, 1994; 65 FR 55189, Sept. 13, 2000; 67 FR 19112, Apr. 18, 2002]
§ 218.303
May I credit rental towards royalty?
(a)(1) For Class II leases as defined in 30 CFR 206.351, and for Class III leases as defined in that section that elect under 43 CFR 3200.7(a)(2) to be subject to all of the BLM regulations promulgated for leases issued after August 8, 2005 you may credit the annual rental that you paid before the first day of the year for which the annual rental is owed against the royalty due for the lease year for which the rental was paid. You may not apply any annual rental paid in excess of the royalty due for a particular lease year as a credit against any royalty due in any subsequent lease year.
(2) For purposes of this section, the term “royalty” includes any advanced royalty payable under 30 U.S.C. 1004(f) for a cessation of production.
(b) If portions of your lease are located both within and outside of a participating area, you may credit against royalty under paragraph (a) only that percentage of the rental you paid that corresponds to the percentage of the lease within the participating area on a per-acre basis.
[72 FR 24468, May 2, 2007]
§ 218.304
May I credit rental towards direct use fees?
You may not credit annual rental toward direct use fees you are required to pay that year under § 206.356(b). You must pay the direct use fees in addition to the annual rental due.
[72 FR 24468, May 2, 2007]
§ 218.305
How do I pay advanced royalties I owe under BLM regulations?
If you pay advanced royalties under 43 CFR 3212.15(a)(1) to retain your lease:
(a) You must pay an advanced royalty monthly equal to the average monthly royalty you paid under 30 CFR part 206, subpart H (including the amount against which you applied the annual rental as a credit) for the last 3 years the lease was producing. If your lease has been producing for less than 3 years, then use the average monthly royalty payment for the entire period your lease has been producing continuously;
(b) The MMS must receive your advanced royalty payment before the end of each full calendar month in which no production occurs;
(c) You may credit any advanced royalty you pay against production royalties you owe after your lease resumes production. You may not reduce the amount of any production royalty paid for any year below zero.
[72 FR 24468, May 2, 2007]
§ 218.306
May I receive a credit against production royalties for in-kind deliveries of electricity I provide under contract to a State or county government?
(a) You may receive a credit against royalties for in-kind deliveries of electricity you provide under contract to a State or county government if:
(1) The State or county to which you provide electricity would receive a portion of the royalties you paid in money for the lease under 30 U.S.C. 191 or 30 U.S.C. 1019, except as otherwise provided under the Mineral Leasing Act for Acquired Lands, 30 U.S.C. 355, because your lease is located in that State or county. If your lease is located in more than one State or county, the revenues are paid to the respective States or counties based on their proportionate shares of the total acres in the lease;
(2) The MMS approves in advance your contract with the State or county to which you are providing in-kind electricity; and
(3) Your contract provides that you will use the wholesale value of the electricity for the area where your lease is located to establish the specific methodology to determine the amount of the credit; and
(b) The maximum credit you may take under this section is equal to the portion of the royalty revenue that MMS would have paid to the State or county that is a party to the contract had you paid royalty in money on all of the electricity you delivered to the State or county based on the wholesale value of the electricity. You must pay in money any royalty amount that is not offset by the credit allowed under this section, calculated based on the wholesale value of the electricity.
(c) The electricity the State or county government receives from you satisfies the Secretary's payment obligation to the State or county under 30 U.S.C. 191 or 30 U.S.C. 1019.
[72 FR 24468, May 2, 2007]
§ 218.307
How do I pay royalties due for my existing leases that qualify for near-term production incentives under BLM regulations?
If you qualify for a production incentive under BLM regulations at 43 CFR subpart 3212, your royalty due on the production BLM determines to be qualified for a production incentive under 43 CFR 3212.23 and 3212.24 is 50 percent of the amount of the total royalty that would otherwise be due under 30 CFR part 206, subpart H.
[72 FR 24468, May 2, 2007]
Subpart G—Indian Lands [Reserved]

Subpart H—Service of Official Correspondence

Source:
71 FR 51751, Aug. 31, 2006, unless otherwise noted.
§ 218.500
What is the purpose of this subpart?
This subpart contains instructions for designating a specific addressee of record for service of official correspondence using Form MMS-4444, Addressee of Record Designation for Service of Official Correspondence.
§ 218.520
What definitions apply to this subpart?
Address of record is the address to which official correspondence is served.
Addressee of record for service of official correspondence is the person or position to whom official correspondence is served, as specified on Form MMS-4444, or in the absence of such a form, as established in § 218.540(b)(2). The addressee of record in a part 290, subpart B, appeal will be the person or representative making the appeal.
Official correspondence is all correspondence from MMS or our delegates, served on companies related to matters such as: forms reporting, audit and compliance, enforcement notices, rental courtesy notices, and invoices.
§ 218.540
How does MMS serve official correspondence?
MMS will serve all Notices of Noncompliance or Civil Penalty following the procedures in part 241. We will serve all other documents following the procedures in this section.
(a) Method of service. MMS will serve all official correspondence to the addressee of record by one of the following methods:
(1) U.S. Postal Service mail;
(2) Personal delivery made pursuant to the law of the State in which the service is effected; or
(3) Private mailing service (e.g., United Parcel Service, or Federal Express), with signature and date upon delivery, acknowledging the addressee of record's receipt of the official correspondence document.
(b) Selection of addressee of record information. (1) We will address official correspondence to the party shown on the most recently received Form MMS-4444 for the type of correspondence at issue. The company or reporting entity is responsible for notifying MMS of any name or address changes on Form MMS-4444. The addressee of record in a part 290, subpart B, appeal will be the person or representative making the appeal.
(2) If we do not receive addressee of record information from you on Form MMS-4444, we may use the individual name and address, position title, or department name and address in our database, based on previous formal or informal communications or correspondence for the type of official correspondence at issue. Alternately, we may obtain contact information from public records and send correspondence to:
(i) The registered agent;
(ii) Any corporate officer; or
(iii) The addressee of record shown in the files of any State Secretary; Corporate Commission; Federal or state agency that keeps official records of business entities or corporations; or other appropriate public records for individuals, business entities, or corporations.
(c) Dates of service. Except as provided in paragraph (d) of this section, MMS considers official correspondence as served on the date that it is received at the address of record. A receipt, signed and dated by any person at that address, is evidence of service and of the date of service. If official correspondence is served in more than one manner and the dates differ, the date of the earliest service is used[smc1].
(d) Constructive service. If we cannot make delivery to the addressee of record after making a reasonable effort, we deem official correspondence as constructively served 7 days after the date that we mail the document. This provision covers situations such as those where no delivery occurs because:
(1) The addressee of record has moved without filing a forwarding address;
(2) The forwarding order has expired;
(3) Delivery was expressly refused; or
(4) The document was unclaimed and the attempt to deliver is substantiated by either:
(i) The U.S. Postal Service;
(ii) A private mailing service, as described in this section; or
(iii) The person who attempted to make delivery using some other method of service.
§ 218.560
How do I submit Form MMS-4444?
A copy of Form MMS-4444 and instructions may be obtained from MMS. It will also be posted on the MMS Web site. Submit the completed, signed form to the address designated on the Form MMS-4444 instructions.
§ 218.580
When do I submit Form MMS-4444?
Initially, you must submit MMS Form-4444 by November 29, 2006, and subsequently, within 2 weeks of any change of your address.
Pt. 219

PART 219—DISTRIBUTION AND DISBURSEMENT OF ROYALTIES, RENTALS, AND BONUSES
Subpart A—General Provision [Reserved]
Subpart B—Oil and Gas, General [Reserved]

Subpart C—Oil and Gas, Onshore
Sec.
219.100
Timing of payment to States.
219.101
Receipts subject to an interest charge.
219.102
Method of payment.
219.103
Payments to Indian accounts.
219.104
Explanation of payments to States and Indian tribes.
219.105
Definitions.

Authority:
Section 104, Pub. L. 97-451, 96 Stat. 2451 (30 U.S.C. 1714).

Source:
49 FR 37347, Sept. 21, 1984, unless otherwise noted.
Subpart A—General Provisions [Reserved]
Subpart B—Oil and Gas, General [Reserved]

Subpart C—Oil and Gas, Onshore
§ 219.100
Timing of payment to States.
A State's share of mineral leasing revenues shall be paid to the State not later than the last business day of the month in which the U.S. Treasury issues a warrant authorizing the disbursement, except for any portion of such revenues which is under challenge and placed in a suspense account pending resolution of a dispute.
§ 219.101
Receipts subject to an interest charge.
(a) Subject to the availability of appropriations, the Minerals Management Service (MMS) shall pay the State its proportionate share of any interest charge for royalty and related monies that are placed in a suspense account pending resolution of matters which will allow distribution and disbursement. Such monies not disbursed by the last business day of the month following receipt by MMS shall accrue interest until paid.
(b) Upon resolution, the suspended monies found due in paragraph (a) of this section, plus interest, shall be disbursed to the State under the provisions of § 219.100.
(c) Paragraph (a) of this section shall apply to revenues which cannot be disbursed to the State because the payor/lessee provided incorrect, inadequate, or incomplete information to MMS which prevented MMS from properly identifying the payment to the proper recipient.
§ 219.102
Method of payment.
The MMS shall disburse monies to a State either by Treasury check or by Electronic Funds Transfer (EFT). Should a State prefer to receive its payment by EFT, it should request this payment method in writing to the Minerals Management Service, Minerals Revenue Management, P.O. Box 5760, Denver, Colorado 80217-5760.
[57 FR 41868, Sept. 14, 1992, as amended at 58 FR 64903, Dec. 10, 1993; 67 FR 19112, Apr. 18, 2002]
§ 219.103
Payments to Indian accounts.
Mineral revenues received from Indian leases shall be transferred to the appropriate Indian accounts managed by the Bureau of Indian Affairs (BIA) for allotted and tribal revenues. These accounts are specifically designated Treasury accounts. Revenues shall be transferred to the Indian accounts at the earliest practicable date after such funds are received, but in no case later than the last business day of the month in which revenues are received by the MMS.
§ 219.104
Explanation of payments to States and Indian tribes.
(a) Payments to States and BIA on behalf of Indian tribes or Indian allottees discussed in this part shall be described in Explanation of Payment reports prepared by the MMS. These reports will be at the lease level and shall include a description of the type of payment being made, the period covered by the payment, the source of the payment, sales amounts upon which the payment is based, the royalty rate, and the unit value. Should any State or Indian tribe desire additional information pertaining to mineral revenue payments, the State or tribe may request this information from the MMS.
(b) The report shall be provided to: (1) States not later than the 10th day of the month following the month in which MMS disburses the State's share of royalties and related monies; (2) the BIA on behalf of tribes and Indian allottees not later than the 10th day of the month following the month the funds are disbursed by MMS.
(c) Revenues that cannot be distributed to States, tribes, or Indian allottees because the payor/lessee provided incorrect, inadequate, or incomplete information, preventing MMS from properly identifying the payment to the proper recipient, shall not be included in the reports until the problem is resolved.
§ 219.105
Definitions.
Terms used in this subpart shall have the same meaning as in 30 U.S.C. 1702.
Pt. 220

PART 220—ACCOUNTING PROCEDURES FOR DETERMINING NET PROFIT SHARE PAYMENT FOR OUTER CONTINENTAL SHELF OIL AND GAS LEASES
Sec.
220.001
Purpose and scope.
220.002
Definitions.
220.003
Information collection.
220.010
NPSL capital account.
220.011
Schedule of allowable direct and allocable joint costs and credits.
220.012
Overhead allowance.
220.013
Unallowable costs.
220.014
Allocation of joint costs and credits.
220.015
Pricing of materiel purchases, transfers, and dispositions.
220.020
Calculation of the allowance for capital recovery.
220.021
Determination of net profit share base.
220.022
Calculation of net profit share payment.
220.030
Maintenance of records.
220.031
Reporting and payment requirements.
220.032
Inventories.
220.033
Audits.
220.034
Redetermination and appeals.

Authority:
Sec. 205, Pub. L. 95-372, 92 Stat. 643 (43 U.S.C. 1337).

Source:
45 FR 36800, May 30, 1980, unless otherwise noted. Redesignated at 48 FR 1182, Jan. 11, 1983, and further redesignated at 48 FR 35642, Aug. 5, 1983.
§ 220.001
Purpose and scope.
(a) This part 220 establishes accounting procedures for determining the net profit share base and calculating net profit share payments due the United States for the production of oil and gas from OCS leases.
(b) The procedures established by this part 220 apply to any OCS lease issued by the Department of the Interior under any bidding system established by § 260.110(a) of this chapter which has a net profit share component.
[45 FR 36800, May 30, 1980, as amended at 46 FR 29689, June 2, 1981. Redesignated at 48 FR 1182, Jan. 11, 1983, and at 48 FR 35642, Aug. 5, 1983]
§ 220.002
Definitions.
For purposes of this part 220:
Allowance for capital recovery means the amount calculated according to procedures specified in § 220.020. This amount allows a premium for risk initially undertaken by the lessee and a return on investment made during the capital recovery period. It is provided in lieu of interest on equipment and materiel charged to the NPSL capital account.
Capital recovery period means the period of time that begins on the date of issuance of the NPSL and ends on the last day of the month during which the sooner of the following occurs:
(1) The lessee completes the last well on the first platform specified in the development and production plan originally approved by the MMS, with any approved amendments thereto, and installation of wellhead equipment. In the event the last well is dry, then the capital recovery period shall be deemed to have ended with the determination that the last well is non-productive;
(2) The balance in the NPSL capital account changes from a debit balance to a credit balance; or
(3) The lessee, at his election, chooses to terminate the capital recovery period. A decision to terminate the capital recovery period prior to the events specified in paragraphs (a) (1) and (2) of this definition shall be communicated in writing to the Director and shall be irrevocable.
Controllable materiel means materiel which at the time is so classified in the Materiel Classification Manual as most recently recommended by the Council of Petroleum Accountants Societies of North America.
Cost means an expenditure or an accrual incurred by a lessee in conducting NPSL operations.
Cost pool means a grouping of costs identified with more than one OCS lease, whether the leases are NPSLs or other types of leases.
Credit means a payment, rebate, reimbursement to a lessee, or other reduction in cost or increase in revenue attributable to NPSL operations.
Direct cost means any cost listed in § 220.011 that benefits only NPSL operations.
Director means the Director of MMS, Washington, DC, or his delegate.
Field employee means an employee below a first level supervisor who is directly employed in the NPSL project area.
First level supervisor means an employee whose primary function in NPSL operations is the direct supervision of other employees and/or contract labor directly employed on the NPSL project area in a field operating capacity.
G & G means geological, geophysical, geochemical and other similar investigations carried out on the NPSL tract.
Joint cost means any cost listed in § 220.011 that benefits NPSL operations and one or more other operations of the lessee or an outside party.
Lessee means a person authorized by an OCS lease, or an approved assignment thereof, to develop and produce oil and gas, including all parties holding such authority by or through the lessee, and the person designated to conduct NPSL operations.
Lessee's cost of allowed employee absence means the lessee's cost of holiday, vacation, sickness, disability benefits, jury duty and other customary excused allowances.
Materiel means equipment, apparatus, and supplies.
Net profit share base means the end of the month credit balance in the NPSL capital account determined pursuant to § 220.021. The net profit share base is the production revenue remaining after subtracting all allowable costs and adding all allowable credits (including production revenue) in accordance with the procedures established by this part 220.
Net profit share payment means the portion of the net profit share base payable to the United States.
Net profit share rate means the percentage share of the net profit share base payable to the United States. The percentage share may be fixed in the notice of OCS lease sale or be the bid variable, depending upon the bidding system used, as established by § 260.110(a) of this chapter.
NPSL means a net profit share lease, which is an OCS lease that provides for payment to the United States of a percentage share of the net profits for production of oil and gas from the tract. This percentage share may be fixed in the notice of OCS lease sale or be the bid variable, depending on the bidding system used, as established by § 260.110(a) of this chapter.
NPSL operations means all activities subsequent to issuance of the NPSL necessary and proper for the exploration, development, operation, maintenance, and final abandonment of the NPSL property.
NPSL project area means the NPSL tract, offshore facilities, and shore base facilities.
NPSL property means the NPSL tract, and materiel and offshore facilities acquired for use in NPSL operations and that are installed and/or used on the NPSL tract.
NPSL tract means a tract subject to an NPSL.
OCS lease means a Federal lease for oil and gas issued under the OCSLA.
OCS lease sale means the DOI proceeding by which leases for certain OCS tracts are offered for sale by competitive bidding and during which bids are received, announced, and recorded.
Offshore facilities means platform and support systems located offshore that are necessary to conduct NPSL operations, e.g., oil and gas handling facilities, living quarters, offices, shops, cranes, electrical supply equipment and systems, fuel and water storage and piping, heliport, marine docking installations, communication facilities, and navigation aids.
Outside party means any person who is not a lessee.
Person means person as defined in part 260 of this chapter.
Personal expenses means travel and other reasonable reimbursable expenses of lessee's employees.
Production means all oil, gas, or other hydrocarbon products produced, removed, saved, or sold from the NPSL property. Gas and liquids of all kinds are included in production. Production includes the allocated share of production from a unit of which the NPSL is a part.
Production revenue means the value of all production attributable to an NPSL property, which value is determined in accordance with § 260.110(b) of this chapter.
Railway receiving point or recognized barge terminal means the location that a vendor would use in determining the sale price to the lessee of new materiel to be delivered to the NPSL project area.
Reliable supply store means a recognized source or common stock point for the particular materiel involved.
Shore base facilities means onshore facilities necessary for NPSL operations, including:
(1) Shore base support facilities, e.g., a receiving and trans-shipment point for materiel, staging area for shuttling personnel to and from the NPSL tract, a communication, scheduling, and dispatching center; and
(2) Shore base production facilities, e.g., pumps, separating facilities, gas plants, and tankage for production from the NPSL tract.
Technical employees means those employees having special and specific engineering, geological or other professional skills, and whose primary function in NPSL operations is the handling and resolution of specific operating conditions and problems for the benefit of NPSL operations.
Tract means land located on the OCS that is offered for lease through an OCS lease sale and that is identified by a leasing map or an official protraction diagram prepared by DOI.
[45 FR 36800, May 30, 1980, as amended at 46 FR 29689, June 2, 1981. Redesignated and amended at 48 FR 1182, Jan. 11, 1983. Redesignated at 48 FR 35642, Aug. 5, 1983]
§ 220.003
Information collection.
(a) The information collection requirements of this part have been approved by OMB under 44 U.S.C. 3501 et seq. and assigned OMB Clearance Number 1010-0073. The information will be used to determine all allowable direct and allocable joint costs incurred during the term of the lease, appropriate overhead allowances permitted on these costs pursuant to § 220.012, and allowances for capital recovery calculated pursuant to § 220.020. The information collection is mandatory in accordance with the Federal Oil and Gas Royalty Management Act of 1982, 30 U.S.C. 1701 et seq.
(b) Public reporting burden is estimated to average 16 hours for each annual and monthly lease report, including time spent reviewing instructions, searching existing data sources, gathering and maintaining the data needed, and completing and reviewing the collection of information. Send comments regarding the burden estimate or any other aspect of this collection of information, including suggestions for reducing burden, to the Information Collection Clearance Officer, Minerals Management Service, 281 Elden Street, Herndon, Virginia 22070; and to the Office of Information and Regulatory Affairs, Office of Management and Budget, Paperwork Reduction Project 1010-0073, Washington, DC 20503.
[57 FR 41868, Sept. 14, 1992, as amended at 58 FR 64903, Dec. 10, 1993]
§ 220.010
NPSL capital account.
(a) For each NPSL tract, an NPSL capital account shall be established and maintained by the lessee for NPSL operations. The NPSL capital account shall include debit entries for all allowable direct and allocable joint costs incurred during the term of the lease, appropriate overhead allowances permitted on these costs pursuant to § 220.012, and allowances for capital recovery calculated pursuant to § 220.020. The NPSL capital account shall be credited with production revenues attributable to the NPSL and any other credits arising from NPSL activities.
(b) The NPSL capital account shall be kept on an accrual basis.
§ 220.011
Schedule of allowable direct and allocable joint costs and credits.
The costs and credits specified in paragraphs (a) through (p) of this section may be charged direct, or allocated to NPSL operations, as appropriate, in accordance with § 220.014.
(a) Lease rental. The rent paid by the lessee for the NPSL tract is allowable.
(b) Labor. (1)(i) Salaries and wages of lessee's field employees, first level supervisors and technical employees employed in the NPSL project area in NPSL operations are allowable if such costs are not charged under paragraph (g) of this section.
(ii) Salaries and wages of technical employees within technical branches of the lessee's organization who are either temporarily or permanently assigned to, and directly employed in NPSL operations are allowable provided that such employees work “full time” on some particular aspect of NPSL operations or some specific technical problem. Excluded from this category are employees assigned a role in NPSL operations as a duty collateral with other duties that do not directly benefit NPSL operations.
(iii) Salaries and wages of technical employees within technical branches of the lessee's organization who are assigned technical tasks directly related to NPSL operations may be allowable. Costs may be charged to the NPSL if supported by adequate time records showing the nature of the task and the hours spent on that task.
(2) Lessee's cost of allowed employee absence paid to employees whose salaries and wages are chargeable to NPSL operations under paragraphs (b)(1) (i) and (ii) of this section are allowable.
(3) Expenditures or contributions made pursuant to assessments imposed by governmental authority that are applicable to lessee's costs chargeable to NPSL operations under paragraphs (b)(1) (i) and (ii) and (b)(2) of this section are allowable.
(4) Reasonable personal expenses, including allowable relocation costs of employees whose salaries and wages are chargeable to NPSL operations under paragraphs (b)(1) (i) and (ii) of this section and that are paid by the lessee or for which the employees are reimbursed under the lessee's normal practice are allowable except as limited by § 220.013(g).
(i) Allowable relocation costs include:
(A) Travel expenses, including transportation, lodging, subsistence, and reasonable incidental expenses of the employee and members of his immediate family and transportation of his household and personal effects to the new location.
(B) Other necessary and reasonable expenses normally incident to relocation, such as costs of cancelling an unexpired lease, disconnecting and reinstalling household applicances, and purchases of insurance against damages to or loss of personal property are allowable. Costs of cancelling an unexpired lease shall not exceed three times the monthly rental.
(C) Closing costs (i.e., brokerage fees, legal fees, appraisal fees, etc.) for the sale of the employee's actual residence when notified of the transfer are allowable; and
(D) Continuing costs of ownership of the vacant former actual residence being sold, such as continuing mortgage principal and interest payments, maintenance of building and grounds (exclusive of fixing-up expenses), utilities, taxes, property insurance, etc., after settlement date of lease or date of new permanent residence are allowable.
(ii) The combined total of costs listed in paragraphs (b)(4)(i) (C) through (D) of this section shall not exceed 8 percent of the sales price of the property sold.
(iii) Section 220.013(g) specifies employee relocation expenses that are not allowable as a charge to NPSL operations.
(5) Lessee's current costs of established plans for employee's group life insurance, hospitalization, pension, retirement, stock purchase, thrift, bonds, and other benefit plans of a like nature that are made available to all of lessee's employees on an equitable basis, applicable to lessee's labor cost chargeable to NPSL operations under paragraphs (b)(1) (i) and (ii) and (b)(2) of this section, are allowable. The amount of these charges shall be lessee's actual cost not to exceed 23 percent of the total charges under paragraphs (b)(1) (i) and (ii) and (b)(2) except that the Director may from time to time establish a different maximum percentage.
(6) Charges for expenses incurred under paragraphs (b)(2) through (b)(5) of this section may be made to NPSL accounts on a “when and as paid” basis or by a percentage assessment method. If the percentage assessment method is used, it shall be based upon the lessee's actual cost experience expressed as a percentage of costs chargeable under paragraphs (b)(1) (i) and (ii) and (b)(2) of this section. Under either method the lessee's own cost of administering the plans and paying the salaries and benefits defined in this paragraph shall be excluded. In determining actual cost experience of an employee benefit plan, any dividend or refunds received that are applicable to insurance or annuity policies shall be used to reduce the cost of such policies.
(c) Materiel. (1) Materiel purchased or furnished by a lessee as NPSL property shall be charged or credited at amounts specified in § 220.015. The purchase and inventorying of materiel is subject to the conditions and provisions in § 220.032.
(2) Charges to an NPSL account shall be made only for such materiel purchased or furnished as NPSL property as is reasonably practical and consistent with efficient and economical operations. The accumulation of surplus stocks shall be avoided.
(3) Credit for salvaged or returned materiel shall be made to the NPSL capital account. When the amount originally charged qualifies for the allowance for capital recovery in § 220.020, the credit shall be calculated pursuant to § 220.021(a)(3).
(d) Transportation. Transportation of employees and materiel necessary for NPSL operations to, from, and within the NPSL project area, are allowable, but subject to the following limitations:
(1) If materiel is moved to the NPSL project area, no charge shall be made to NPSL operations for a distance greater than the distance from the nearest reliable supply store, recognized barge terminal, or railway receiving point where like materiel is normally available, unless agreed to by the Director.
(2) If surplus materiel is moved from the NPSL project area, no charge shall be made to NPSL operations for a distance greater than the distance to the nearest reliable supply store, recognized barge terminal, or railway receiving point unless agreed to by the Director. No charge shall be made to NPSL operations for moving materiel to other properties owned by or under the control of a lessee, unless agreed to by the Director.
(3) In the application of paragraphs (d)(1) and (d)(2) of this section, there shall be no equalization of actual gross trucking costs of $200 or less, excluding accessorial charges.
(e) Contract services. Except when excluded by paragraph (f) of this section and/or § 220.013(c), the cost of services and utilities provided under contract by outside parties to the lessee and which constitute proper and necessary NPSL operations or support for NPSL operations, and rental charges paid to outside parties for the use of equipment used in the NPSL project area in support of NPSL operations, may be charged to NPSL operations subject to the following conditions and limitations:
(1) Contract services (including professional consulting services and contract services of technical personnel) that are entirely performed in the NPSL project area and benefit exclusively NPSL operations may be charged at the rates specified in the contract.
(2) Contract services (including professional consulting services and contract services of technical personnel) that are entirely performed in the NPSL project area and benefit the NPSL operations and operations on other tracts must be allocated among all tracts benefited and only that portion representing services benefiting the NPSL tract charged to NPSL operations.
(3) Contract services (including professional consulting services and contract services of technical personnel) that are performed at sites outside the NPSL project area may be charged to NPSL operations only if:
(i) The contracted services charged to the NPSL operations benefit only the NPSL tract or support NPSL operations;
(ii) The contract under which such services are provided deals exclusively with services benefiting the NPSL tract or NPSL operations, or the costs of the contract services which are applicable to the NPSL tract or NPSL operations are separately and specifically identified in the contract; and
(iii) Services specified in the contract relate to the resolution of specific technical problems confronting NPSL operations, or specific engineering design problems related to equipment or facilities required for NPSL operations.
(4) The cost of any contract service related to research and development is specifically excluded, as are contract services calling for feasibility studies not directly related to specific engineering design problems or alternatives for equipment and facilities required by NPSL operations.
(f) Legal expenses. Expense of handling, investigating and settling litigation or claims, discharging of liens, payments of judgments and amounts paid for settlement of claims incurred in or resulting from NPSL operations, or necessary to protect or recover the NPSL property are allowable, except those costs listed in § 220.013(f) as unallowable. This includes the salaries and wages of lessee's legal staff and the expense of outside attorneys who are assigned to matters described in this paragraph if supported by adequate time records showing the nature of the matter, its direct relationship to NPSL operations, and the hours spent on the matter.
(g) Rental of equipment and facilities furnished by lessee. (1)(i) The NPSL capital account shall be charged for the use of equipment and facilities owned by a lessee that are proper and necessary for NPSL operations, including shore base and offshore facilities and pipelines from the tract to shore base production facilities, and that are not NPSL property. Rental charges shall be made at rates based upon actual costs of acquisition, construction, and operation. Such rates may include labor, the cost of setting up and dismantling equipment, maintenance, repairs, other operating expenses, insurance, taxes, depreciation (calculated using a method consistent with generally accepted accounting principles, consistently applied) and a return on the remaining undepreciated basis not to exceed 8 percent per year, except that the Director may from time to time establish a different maximum percentage. Any cost of acquiring real property in excess of that reasonably required to support the facilities furnished for NPSL operations shall not be included in the costs used to establish these rates. Rates charged shall not exceed average commercial rates for equipment and facilities of similar nature and capability currently prevailing in the vicinity of the NPSL project area.
(ii) The term “equipment and facilities” is used in the broad sense to include equipment that may be mobile or semimobile and also installations that may be semipermanent or permanent in nature. Such equipment and facilities listed below shall be charged on the basis indicated.
Equipment/facilities | Basis of charge
A. Mobile equipment:
Aircraft | Hour.
Automobiles | Mile or hour.
Trucks | Mile or hour.
Tractors | Hour.
Bulldozers | Hour.
Mobile cranes | Hour.
Trailer-mounted test separators | Hour.
Truck-mounted cement mixers | Hour.
Boats | Day or hour.
House trailers | Day.
B. Semimobile equipment:
Drill rigs | Foot or day.
Workover rigs | Hour.
Pulling units | Hour.
Derricks | Day.
Drilling tender | Day.
Barges | Day.
C. Semipermanent installations:
Skid-mounted separators | Day or volume.
Skid-mounted compressors | Day or volume.
D. Permanent installations:
Compressor stations | Volume.
Saltwater disposal wells | Volume or wells.
Source water wells and supply systems | Volume.
Roads | Wells.
Production/drilling platform | Volume or wells.
Canals | Wells.
Dock | Wells.
Oil storage and loading facilities. | Volume.
Gathering systems and pipeline | Volume.
ACT systems | Volume.
Laboratory services (excluding research work) | Hour or unit.
Shore base production facilities | Volume.
Shore base support facilities | Wells.
E. Miscellaneous:
Drill pipe | Foot or day.
Casing setting tools | Day.
Well testing equipment | Day.
Equipment and facilities that are not listed shall be charged on a basis consistent with the nature of the use.
(2) In lieu of charges in paragraph (g)(1) of this section, the lessee may elect to use average commercial rates prevailing in the vicinity of the NPSL project area less 20 percent. For automotive equipment, the lessee may elect to use rates established by the Director. For other equipment for which no commercial rate exists, the lessee shall submit the basis for determining such costs to the Director for approval.
(h) Damages and losses to NPSL property. All costs necessary for the repair or replacement of NPSL property made necessary because of damages or losses incurred by fire, flood, storm, theft, accident, or other causes not covered by insurance, except those resulting from lessee's negligence or willful misconduct may be charged to the NPSL capital account. Any settlement received from an insurance carrier should be credited to NPSL operations when received.
(i) Taxes. All taxes, except income taxes, profit share payments, and taxes based upon income, that are assessed or levied upon or in connection with NPSL operations and which have been paid by the lessee are allowable. Allowed taxes shall include, but not be limited to, production, severance, excise, ad valorem, and mineral taxes.
(j) Insurance. (1) Net premiums paid for insurance required to be carried for NPSL operations are allowable. For NPSL operations in which the lessee may act as self-insurer for Workmen's Compensation and Employer's Liability, the lessee may include the risk under its self-insurance program in providing coverage under State and Federal laws and charge NPSL operations at lessee's cost not to exceed manual rates.
(2) NPSL operations shall be credited for all reimbursements for costs of damage to NPSL property or personal injury. Reimbursements for damaged NPSL property shall be credited as follows:
(i) If the damaged NPSL property is replaced or repaired, to the NPSL capital account charged for the cost of replacement or repair; or
(ii) If the damaged NPSL property is not replaced or repaired, to the NPSL capital account except that if the cost of the property originally qualified for the allowance for capital recovery in § 220.020, the credit shall be calculated pursuant to § 220.021(a)(3).
(k) Communications. Costs of leasing, acquiring, installing, operating, repairing and maintaining communication systems, including radio, microwave facilities, and computer production controls for the NPSL operations are allowable. If communication facilities systems serving the NPSL tract serve operations and/or facilities outside the NPSL project area, charges to NPSL operations shall be made as provided in paragraph (g) of this section or shall be allocated to NPSL operations in accordance with § 220.014.
(l) Ecological and environmental. Costs incurred in the NPSL project area as a result of statutory regulations for archeological and geophysical surveys relative to identification and protection of cultural resources and other environmental or ecological surveys required by the Bureau of Land Management or other regulatory authority, may be charged to the NPSL capital account. Also, the costs to provide or have available pollution containment and removal equipment, including payments to organizations and/or funds which provide equipment and/or assistance in the event of oil spills or other environmental damage are allowable. The costs of actual control and cleanup of oil spills and resulting responsibilities required by applicable laws and regulations are allowable, except that a charge shall not be allowed for any such costs attributable to the lessee's negligence or willful misconduct.
(m) Dry or bottom hole contributions. The costs of dry or bottom hole contributions made to obtain information about the structure or other characteristics of the geology underlying the NPSL tract are allowable.
(n) Abandonment costs. Actual costs incurred in the plugging of wells, dismantling of platforms and other facilities and in the restoration of the NPSL project area shall be charged to the NPSL capital account only when incurred (i.e., not on an accrual basis), except that costs incurred after the cessation of production shall not be charged to the NPSL capital account. Abandonment costs in excess of offsetting revenues shall not form the basis of any claim against the United States.
(o) Other costs. Any other costs not covered in paragraphs (a)-(n) of this section and not disallowed by § 220.013 that are incurred by the lessee in the necessary and proper conduct of NPSL operation and are approved by the Director, are allowable. Approval of a plan of development and production for the NPSL tract by the Director shall be considered sufficient approval for these other costs provided they are separately identified in said plan of development and production. Such separate identification shall note the nature of these other costs and may include an estimate of their magnitude. Any cost approvals under this paragraph for which the specific amounts have not been itemized are presumed to be approved provided they fall within the limits for a prudent operator. Approval of costs under this paragraph shall be approval solely for the purposes of determining allowable costs and shall not preclude a subsequent adjustment at audit of the amount of such costs.
(p) Other credits. Credit shall be given to the NPSL capital account, depending on when it is incurred, for NPSL property leased or used in non-NPSL operations, for the sale of information derived from test wells and G & G, and for any and all amounts earned or otherwise due lessee as a result of NPSL operations.
[45 FR 36800, May 30, 1980. Redesignated at 48 FR 1182, Jan. 11, 1983, and at 48 FR 35642, Aug. 5, 1983, as amended at 67 FR 19112, Apr. 18, 2002]
§ 220.012
Overhead allowance.
(a) During the capital recovery period the overhead allowance shall be calculated on a percentage basis at the rate of 4 percent of allowable direct and allocable joint costs charged to the NPSL capital account, exclusive of costs specified in paragraph (c) of this section. This overhead allowance shall be debited to the NPSL capital account in accordance with § 220.021(b)(2).
(b) For each month after the end of the capital recovery period, an overhead allowance shall be calculated on a percentage basis at the rate of 10 percent of allowable direct and allocable joint costs charged to the NPSL capital account, exclusive of costs specified in paragraph (c) of this section. This overhead allowance shall be debited to the NPSL capital account in accordance with § 220.021(c)(2).
(c) Overhead shall not be charged on the value of:
(1) Lease rental (§ 220.011(a));
(2) Contract services (§ 220.011(e));
(3) Taxes (§ 220.011(i));
(4) Re-injected hydrocarbons, originally produced from the NPSL tract, that are charged under § 220.011(c); and
(5) Credits for materiel charged under § 220.011(c) that are salvaged, returned, or used for the benefit of non-NPSL operations.
§ 220.013
Unallowable costs.
The following costs shall not be charged as direct or joint costs to NPSL operations:
(a) Bonus payments to the United States;
(b) Interest (except as permitted under § 220.011(g));
(c) Depreciation, depletion, amortization, or any other charge for capital recovery for materiel charged to the NPSL capital account under § 220.011(c), except as explicitly provided by the allowance for capital recovery calculated according to § 220.020;
(d) The cost of taking inventory;
(e) Research and development costs;
(f) The following legal expenses:
(1) The costs of litigation against the Federal government;
(2) Fines or penalties levied by any Federal agency;
(3) Settlement of claims or other litigation resulting from the lessee's violation of regulatory requirements or negligence; and
(4) The cost of the lessee's legal staff or expense of outside attorneys, except as explicitly allowed under § 220.011(f);
(g) The following employee relocation costs (whether incurred by the employee or the lessee):
(1) Loss on the sale of a home;
(2) Purchase price of a home in the new location;
(3) Payments for employee income taxes incident to reimbursed relocation costs; and
(4) Any relocation cost in connection with an employee move that is for the primary benefit of the lessee's non-NPSL operations;
(h) The lessee's own cost of administering employee benefit plans;
(i) The cost of acquiring or constructing shore base facilities and real property improvements that are charged to NPSL operations on a rental basis under § 220.011(g);
(j) Rentals on any facilities, the investment costs of which have been charged either directly or as allocable joint costs, to the NPSL capital account; and
(k) Pre-NPSL expenditures.
§ 220.014
Allocation of joint costs and credits.
(a) Joint costs shall be grouped in cost pools for allocation to NPSL and non-NPSL operations in reasonable proportion to the beneficial or causal relationships which exist between a specific cost pool and the operations. That portion of a joint cost pool that may be allocated to NPSL operations is called an allocable joint cost.
(b) The following allocation principles apply in allocating joint costs:
(1) G & G. G & G shall be allocated on a line mile per tract basis.
(2) Wages and salaries. Wages and salaries that are not charged as direct on the basis of time spent on a particular job shall be allocated on a reasonable and equitable basis.
(3) Compensated personal absence, payroll taxes and personal expenses. These items shall be allocated on the same basis as wages and salaries.
(4) Transportation costs. Transportation costs for employees that are not charged direct shall be allocated on the same basis as their wages and salaries.
(c) Joint credits shall be allocated in the same manner as joint costs.
(d) When the NPSL is made a part of a unit, the allowed costs shall be charged to the NPSL capital account on the basis specified in the unit operating agreement as approved by the Director. Revenues and other credits shall be made to the NPSL accounts on the same basis as specified in the approved operating agreement. Joint costs of an NPSL and a non-NPSL tract that are adjacent to one another and are on the same structure shall be allocated on a basis approved by the Director.
§ 220.015
Pricing of materiel purchases, transfers, and dispositions.
(a)(1) Purchased materiel. Except as provided in paragraph (a)(2)(i) of this section, materiel purchased for use in NPSL operations shall be charged to NPSL operations at the price paid, after deduction of any discounts received. Should any purchased materiel be defective or returned to a vendor for other reasons, the credit shall be allocated to NPSL operations when received by the lessee in accordance with § 220.011(c)(3).
(2) Transferred and disposal materiel. An item of materiel, which is acquired by the lessee for use in NPSL operations by means other than purchase or disposed of by any means, shall be priced according to this subparagraph:
(i) Condition A (new) materiel. (A) Tubular goods, except line pipe, shall be priced at the current market price in effect on date of movement on a minimum carload or barge load weight basis, regardless of quantity transferred, equalized to the lowest published price “free on board” (f.o.b.) railway receiving point or recognized barge terminal nearest the NPSL tract where such materiel is normally available.
(B) Line pipe. (1) Movement of less than 30,000 pounds shall be priced at the current price in effect at date of movement, as listed by a reliable supply store nearest the NPSL tract where such materiel is normally available.
(2) Movement of 30,000 pounds or more shall be priced under the provisions for tubular goods pricing in paragraph (a)(2)(i)(A) of this section.
(C) Other materiel shall be priced at the current price in effect at date of movement, as listed by a reliable supply store or f.o.b. railway receiving point nearest the NPSL tract where such materiel is normally available.
(ii) Condition B (good used) materiel. Materiel in sound and serviceable condition and suitable for reuse without reconditioning:
(A) Materiel transferred to the NPSL project area shall be priced at 75 percent of current Condition A price.
(B) Materiel transferred from the NPSL project area shall be priced:
(1) At 75 percent of current Condition A price, if the materiel was originally charged to NPSL operations as Condition A materiel, or
(2) At 65 percent of current Condition A price, if the materiel was originally charged to NPSL operations as Condition B materiel at 75 percent of current Condition A price.
(iii) Conditions C and D (other used) materiel—(A) Condition C. Materiel that is not in sound and serviceable condition and not suitable for its original function until after reconditioning shall be priced at 50 percent of current Condition A price.
(B) Condition D. Materiel no longer suitable for its original purposes but suitable for some other purpose shall be priced on a basis commensurate with its use and comparable with that of materiel normally used for such other purpose. If the materiel has no alternative use it should be priced at prevailing prices as scrap.
(iv) Obsolete materiel. Materiel that is serviceable and usable for its original function and has a value less than Condition A, B, or C materiel may be valued at a price agreed to by the Director. Such price should be the equivalent of the value of the service rendered by such materiel.
(b) Pricing conditions. (1) Loading and unloading costs shall be charged at a rate of 15 cents per hundred weight, or such other rate as may be set by the Director, on all tubular goods movements, in lieu of loading/unloading costs sustained, when the actual hauling costs of such tubular goods is equalized under provisions of § 220.011(d).
(2) Materiel involving erection costs shall be charged at the applicable percentage of the current knocked-down price of new materiel.
(c) When materiel subject to paragraphs (a)(2) (ii) and (iii) of this section is transferred, the cost of reconditioning shall be borne by the receiving party.
§ 220.020
Calculation of the allowance for capital recovery.
(a) For purposes of this section, the cost base for the allowance for capital recovery in a particular month shall consist of the sum of:
(1) All allowable direct and allocable joint costs chargeable to the NPSL capital account during the month less any costs specified in § 220.012(c); plus
(2) The value of contract services chargeable to the NPSL capital account during the month pursuant to § 220.011(e); plus
(3) The capital recovery period overhead allowance, calculated in accordance with § 220.012(a), that is chargeable to the NPSL capital account for the month; less
(4) Production revenues and other credits received during the month.
(b) If the cost base for a month is greater than zero (that is, if the sum of the charges specified in paragraphs (a) (1) through (3) of this section exceeds the value of production revenues and other credits), the allowance for capital recovery shall be calculated by multiplying the cost base by the capital recovery factor, and shall be debited to the NPSL capital account as specified in § 220.021(b).
(c) If the cost base for a month is less than zero, the allowance for capital recovery for the NPSL capital account shall be calculated by multiplying the resulting negative cost base by the capital recovery factor. The negative product of this calculation shall be debited to the NPSL capital account as specified in § 220.021(b).
(d) No allowance for capital recovery shall be calculated on the charges or credits related to any time period after the end of the capital recovery period.
§ 220.021
Determination of net profit share base.
(a) During each month of the lease term, the NPSL capital account shall be:
(1) Debited with allowable direct and allocable joint costs;
(2) Credited with an amount reflecting the production revenues for the month, calculated in accordance with § 260.110(b) of this chapter.
(3) Credited with amounts properly credited back to the NPSL capital account as specified in § 220.011(p). Credits associated with charges to the NPSL capital account during the capital recovery period, however, shall first be increased by the value of the credit multiplied by the recovery factor, before crediting that sum to the NPSL capital account.
(b) At the end of each month of the lease term during the capital recovery period:
(1) The transactions specified in paragraph (a) of this section shall be made to the NPSL capital account.
(2) The capital recovery period overhead allowance shall be calculated in accordance with § 220.012(a) and debited to the NPSL capital account.
(3) The allowance for capital recovery shall be calculated in accordance with § 220.020 and the allowance debited (or the negative allowance debited, as appropriate) to the NPSL capital account. (A debit entry of a negative allowance for capital recovery shall have the same effect as a credit entry of the absolute value of the allowance for capital recovery.)
(4) The balance in the NPSL capital account shall be calculated. If, as a result of the accounting transactions described in paragraphs (b) (1) through (3) of this section, there is a credit balance in the NPSL capital account, the capital recovery period will be considered terminated as of this month. The credit balance will be forwarded to the next month, which will be the first month for which a profit share payment is due.
(c) At the end of each month of the lease term following the end of the capital recovery period:
(1) The transaction specified in paragraph (a) of this section shall be made to the NPSL capital account.
(2) An overhead allowance shall be calculated in accordance with § 220.012(b) and debited to the NPSL capital account.
(3) The balance in the NPSL capital account shall be calculated.
(d) If, as a result of the accounting transactions described in paragraph (c) of this section, there is a credit balance in the NPSL capital account, this credit balance is the net profit share base for that month. The opening debit and credit balances in the NPSL capital account for any month following a month in which there is a credit balance in the NPSL capital account (except as provided in paragraph (b)(4)) of this section shall be zero.
(e) If, as a result of the accounting transactions described in paragraph (b) or (c) of this section, there is a debit balance in the NPSL capital account, this debit balance shall be the opening debit balance in the NPSL capital account for the following month.
(f) Any credit balance in the NPSL capital account shall become the net profit share base as described in this section. Any debit balance in the NPSL capital account shall be maintained only insofar as necessary for the determination of profit share payments. Such debit balance shall not represent a claim against the United States.
[45 FR 36800, May 30, 1980. Redesignated at 48 FR 1182, Jan. 11, 1983, and at 48 FR 35642, Aug. 5, 1983, and amended at 55 FR 1210, Jan. 12, 1990]
§ 220.022
Calculation of net profit share payment.
The net profit share payment shall be calculated by multiplying the net profit share base calculated in accordance with § 220.021 by the net profit share rate. The net profit share payment shall be paid to the United States in accordance with § 220.031.
§ 220.030
Maintenance of records.
(a) Each lessee subject to this part 220 shall establish and maintain such records as are necessary to determine for each NPSL:
(1) The volume and disposition of all oil and gas production saved, removed or sold for each month;
(2) The value of all oil and gas production saved, removed or sold for each month;
(3) The amount and description of costs and credits to the NPSL capital account;
(4) The amount and description of all costs of acquisition, construction, and operation of equipment and facilities furnished by the lessee and charged to the NPSL capital account under § 220.011(g). Such records shall include worksheets or other documents that indicate the method used to calculate the amount of each charge made under § 220.011(g);
(5) The cumulative balance of costs and credits to the NPSL capital account; and
(6) The inventory of materiel.
(b) The ledger cards showing the charges and credits to the NPSL capital account shall be maintained until thirty-six months after the cessation of NPSL operations by the lessee. All other documents, journals and records shall be maintained for thirty-six months from the due date or date of mailing of the statement of account on an NPSL, whichever comes later, except that nothing in these regulations shall limit the time of investigation or the need to produce records when prima facie evidence of fraud or willful misconduct is obtained with respect to the government's interest in the NPSL.
§ 220.031
Reporting and payment requirements.
(a) Each lessee subject to this part shall file an annual report during the period from issuance of the NPSL until the first month in which production revenues are credited to the NPSL capital account. Such report shall list the costs incurred, including allowances applied, credits received, and the balance of the NPSL capital account. Not later than 60 days after the end of the first month in which production revenues are credited to the NPSL capital account, a final report relating to the period shall be filed.
(b) Beginning with the first month in which production revenues are credited to the NPSL capital account, each lessee subject to this part 220 shall file a report for each NPSL, not later than 60 days following the end of each month, containing the following information for the month for which the report is filed:
(1) The volume and disposition of all oil and gas production saved, removed or sold;
(2) The production revenue;
(3) The amount and description of all costs and credits to the NPSL capital account;
(4) The balance of the NPSL capital account; and
(5) The net profit share base and net profit share payment due the United States and the monthly profit share of the lessee.
(c) Each lessee subject to this part 220 shall submit, together with the report required by paragraph (b) of this section, any net profit share payment due the United States for the period covered by the report.
(d) Each lessee subject to this part 220 shall file a report not later than 90 days after each inventory is taken, reporting the controllable materiel on hand, acquired, transferred or used.
(e) Each lessee subject to this part 220 shall file a final report, not later than 60 days following the cessation of production, together with the appropriate net profit share payment, indicating the remaining balance and costs and credits to the NPSL capital account for the period.
(f) Reports required by this section shall be filed with the Director, either separately or as part of the reports that are currently filed.
(g) Interest shall be calculated at the prevailing rate or rates as published in the Bulletin to the Department of the Treasury Fiscal Requirement Manual, in effect for the period or periods over which the net profit share payment is owed, compounded monthly, on the amount of a net profit share payment, from the due date (60 days following the end of each month for which the payment was due) of a net profit share payment until such payment is received by the United States.
§ 220.032
Inventories.
(a) The lessee is responsible for NPSL materiel and shall make proper and timely cost and credit notations for all materiel movements affecting NPSL property. The lessee shall provide only such materiel as may be required for immediate use or is consistent with practical, efficient, and economical operations. The accumulation of surplus stocks shall be avoided by proper materiel control, inventory and purchasing. The lessee shall make timely disposition of idle and surplus materiel through sale.
(b) At reasonable intervals, but at least once every three years, inventories of controllable materiel shall be taken by the lessee. Written notice of intention to take inventory shall be given by the lessee at least 30 days before any inventory is to be taken so that the Director may be represented at the taking of inventory. Failure of the Director to be represented at an inventory shall bind the Director to accept the inventory taken by the lessee, except in the case of willful misrepresentation or fraud.
(c) Inventory shall be valued with any generally accepted accounting method used by the lessee to value the same materiel for financial or income tax reporting purposes, provided that the method is consistently applied throughout the life of the materiel.
(d) Reconciliation shall be made of a physical inventory with the NPSL capital account by the lessee, and a list of overages and shortages shall be available to the Director for audit as provided in § 220.033. Inventory adjustments of controllable materiel shall be made by the lessee to the NPSL capital account for overages and shortages. Controllable materiel removed from physical inventory that has not been credited to NPSL operations under § 220.015(a)(2) shall be credited to NPSL operations at its original value, except that when the cost of the materiel originally qualified for the allowance for capital recovery in § 220.020, the credit shall be calculated pursuant to § 220.021(a)(3).
§ 220.033
Audits.
(a) The accounts of an NPSL lessee or of a contractor of the lessee which are related to NPSL operations shall be subject to audit by DOI or its appointed agent. Where possible, the auditor for DOI shall coordinate audit efforts with other nonoperators, if any. DOI shall have the right to initiate an audit any time within thirty-six months of the due date of the monthly statement that is to be audited or the date that the statement was mailed, whichever is later, provided, however, that audits may not be conducted any more frequently than once every year except upon a showing of fraud or willful misrepresentation.
(b)(1) When nonoperators of an NPSL lease call an audit in accordance with the terms of their operating agreement, the Director shall be notified of the audit call in the same manner as the operator is notified. DOI may elect to send an auditor with the audit team specified by the nonoperators in lieu of calling for a separate audit by DOI.
(2) If DOI determines to call for an audit, DOI shall notify the lessee of its audit call and set a time and place for the audit. Such a notice shall be sent at least thirty days before the suggested time for the audit to allow the nonoperators to join in DOI's audit in lieu of calling for their own audit. The place for the audit will normally be the place where the lessee maintains its records pertaining to the NPSL lease. The lessee shall send copies of the notice to the nonoperators on the lease. The lessee shall use reasonable effort to notify all nonoperators, but failure to include one or more nonoperators in the notification shall not void the notice.
(3) When DOI calls for an audit, DOI may suggest the date and time when the audit may commence. The estimated duration of the audit may be mentioned to the lessee as well as to the other nonoperators who may elect to supply and auditor for their own audit purposes. The lessee's office where the audit will be held may be named or, if not known, inquired about. If a visit to a field plant or field office is contemplated by the government auditor, such a field trip may be mentioned. If DOI expresses a desire to review a period on which the thirty-six month time limitation has expired, it is the lessee's prerogative to allow the review or to request that DOI adhere to the time limitation specified in these regulations.
(c)(1) Exceptions to the accounting by the lessee, whether in favor of the government or the lessee, shall be noted in a report to the lessee. The lessee shall have 60 days from the mailing of a notice of exceptions to agree to the adjustments proposed by the DOI auditor or to object to the proposed adjustments. If the lessee accepts the proposed adjustments, the adjustment shall be booked in the month in which the lessee agrees to the adjustment, except where such adjustment would have resulted in a change in any net profit share payment due the United States. In such a case, there shall be a redetermination of the NPSL capital account pursuant to § 220.034.
(2) If the lessee disagrees with the adjustment, the lessee shall have the right to appeal the adjustment to the Director.
(d) Upon receipt of an agreement by the government auditor that there are no required audit adjustments, upon final determination with respect to any audit adjustment proposed by the government auditor, or upon the lapse of thirty-six months from the due date or date of mailing of the statement of account on an NPSL lease, whichever comes later, the books shall be closed for audit adjustment purposes, except upon a showing of fraud or willful misrepresentation.
(e) Records required to be kept under § 220.030(a) shall be made available for inspection by any authorized agent of DOI at any time during normal business hours upon the request of the Director or other authorized official.
§ 220.034
Redetermination and appeals.
(a) If, as a result of an inspection of records or an audit under § 220.033, the Director determines that there is an error in the NPSL capital account or an error in calculating the net profit share payment, whether in favor of the government or the lessee, the Director shall redetermine the net profit share base and recalculate the net profit share payment due the United States and notify the lessee of the recalculation.
(b) The lessee shall pay any additional amount of net profit share payment owed plus interest, compounded monthly, from the date that the payment was due until the date it is actually paid. Interest shall be calculated at the prevailing rate or rates as published in the Bulletin to the Department of the Treasury Fiscal Requirements Manual, in effect for the period or periods over which the payment is owed.
(c) If the recalculated profit share payment is less than the amount paid the United States, the lessee shall apply such overpayment to the next profit share payment.
(d) Within 30 days after receiving notice of the recalculation as provided in paragraph (a) of this section, the lessee may appeal the decision of the Director in accordance with the appeals provision of 30 CFR part 290.
Pt. 227

PART 227—DELEGATION TO STATES

Delegation of MMS Royalty Functions
Sec.
227.1
What is the purpose of this part?
227.10
What is the authority for information collection?
227.101
What royalty management functions may MMS delegate to a State?
227.102
What royalty management functions will MMS not delegate?

Delegation Proposals
227.103
What must a State's delegation proposal contain?
227.104
What will MMS do when it receives a State's delegation proposal?

Hearing Process
227.105
What are the hearing procedures?

Delegation Process
227.106
What statutory requirements must a State meet to receive a delegation?
227.107
When will the MMS Director decide whether to approve a State's delegation proposal?
227.108
How will MMS notify a State of its decision?
227.109
What if the MMS Director denies a State's delegation proposal?
227.110
When and for how long are delegation agreements effective?

Existing Delegations
227.111
Do existing delegation agreements remain in effect?

Compensation
227.112
What compensation will a State receive to perform delegated functions?

States' Responsibilities To Perform Delegated Functions
227.200
What are a State's general responsibilities if it accepts a delegation?
227.201
What standards must a State comply with for performing delegated functions?
227.300
What audit functions may a State perform?
227.301
What are a State's responsibilities if it performs audits?
227.400
What functions may a State perform in processing production reports and royalty reports?
227.401
What are a State's responsibilities if it processes production reports or royalty reports?
227.500
What functions may a State perform to ensure that reporters correct erroneous report data?
227.501
What are a State's responsibilities to ensure that reporters correct erroneous data?
227.600
What automated verification functions may a State perform?
227.601
What are a State's responsibilities if it performs automated verification?
227.700
What enforcement documents may a State issue in support of its delegated function?

Performance Review
227.800
How will MMS monitor a State's performance of delegated functions?
227.801
What if a State does not adequately perform a delegated function?
227.802
How will MMS terminate a State's delegation agreement?
227.803
What are the hearing procedures for terminating a State's delegation agreement?
227.804
How else may a State's delegation agreement terminate?
227.805
How may a State obtain a new delegation agreement after termination?

Authority:
30 U.S.C. 1735; 30 U.S.C. 196; Pub L. 102-154.

Source:
62 FR 43084, Aug. 12, 1997, unless otherwise noted.

Delegation of MMS Royalty Functions
§ 227.1
What is the purpose of this part?
This part provides procedures to delegate Federal royalty management functions to States under section 205 of the Federal Oil and Gas Royalty Management Act of 1982 (the Act), 30 U.S.C. 1735, as amended by the Federal Oil and Gas Royalty Simplification and Fairness Act of 1996, Pub. L. 104-185, August 13, 1996, as corrected by Pub. L. 104-200. This part also provides procedures to delegate only audit and investigation functions to States under Pub. L. 102-154 for solid mineral leases, geothermal leases and leases subject to section 8(g) of the Outer Continental Shelf Lands Act, 43 U.S.C. 1337(g). This part does not apply to any inspection or enforcement responsibilities of the Bureau of Land Management for onshore leases or the MMS Offshore Minerals Management program for leases on the Outer Continental Shelf.
§ 227.10
What is the authority for information collection?
(a) The information collection requirements contained in this part have been approved by Office of Management and Budget (OMB) under 44 U.S.C. 3501 et seq. and assigned OMB Control Number 1010-0088. We will use the information collected to review and approve delegation proposals from States wishing to perform royalty management functions.
(b) Public reporting burden is estimated as follows. MMS estimates 400 annual burden hours per function for each State performing the delegated functions. The Federal Government will reimburse some of these costs as provided by statute. However, States could incur additional start-up costs, such as purchasing equipment necessary to perform a delegated function, that may not be reimbursable. MMS estimates that, if applicable, each payor or reporter would spend 50 burden hours annually coordinating their interactions and communications among the several States and with MMS. Send comments regarding this burden estimate or any other aspect of this collection of information, including suggestions for reducing burden, to the Information Collection Clearance Officer, Minerals Management Service, 1849 C Street, NW., Washington, DC 20240; and to the Office of Information and Regulatory Affairs, Office of Management and Budget, Attention: Desk Officer for the Interior Department, OMB Control Number 1010-0088, 725 17th Street, NW., Washington, DC 20503.
§ 227.101
What royalty management functions may MMS delegate to a State?
(a) If there are oil and gas leases subject to the Act on Federal lands within your State, MMS may delegate the following royalty management functions for all such Federal oil and gas leases to you under this part:
(1) Receiving and processing production or royalty reports;
(2) Correcting erroneous report data; and
(3) Performing automated verification.
(b) If there are oil and gas leases subject to the Act on Federal lands within your State, MMS may delegate the following royalty management functions for some or all of the Federal oil and gas leases to you under this part:
(1) Conducting audits and investigations; and
(2) Issuing demands, subpoenas, and orders to perform restructured accounting, including related notices to lessees or their designees, and entering into tolling agreements under section 115(d)(1) of the Act, 30 U.S.C. 1725(d)(1).
(c) If there are oil and gas leases offshore of your State subject to section 8(g) of the Outer Continental Shelf Lands Act, 43 U.S.C. 1337 (g), or solid mineral leases or geothermal leases on Federal lands within your State, MMS may delegate authority to conduct audits and investigations for some or all such Federal leases.
[64 FR 36784, July 8, 1999]
§ 227.102
What royalty management functions will MMS not delegate?
This section lists the principal royalty management functions that MMS will not delegate to a State. MMS will not delegate to a State the following functions:
(a) MMS must collect all moneys received from sales, bonuses, rentals, royalties, civil penalties, assessments and interest. MMS also must collect any moneys a lessee or its designee pays because of audits or other actions of a delegated State;
(b) MMS must compare all cash and other payments it receives with payments shown on royalty reports or other documents, such as bills, to reconcile payor accounts. MMS also must disburse all appropriate moneys to States and other revenue recipients, including refunds and interest owed to lessees and their designees;
(c) The Department of the Interior will receive, process, and decide all administrative appeals from demands or other orders issued to lessees, their designees, or any other person, including demands or orders a delegated State issues;
(d) Only MMS may take enforcement actions other than issuing demands, subpoenas and orders to perform restructured accounting. MMS or the appropriate Federal agency will issue notices of non-compliance and civil penalties, collect debts, write off delinquent debts, pursue litigation, enforce subpoenas, and manage any alternative dispute resolution. MMS will conduct, coordinate and approve any settlement or other compromise of an obligation that a lessee or its designee owes;
(e) MMS will decide all valuation policies, including issuing valuation regulations, determinations, and guidelines, and interpreting valuation regulations; and
(f) MMS may reserve additional authorities and responsibilities not included in paragraphs (a) through (f) of this section.

Delegation Proposals
§ 227.103
What must a State's delegation proposal contain?
If you want MMS to delegate royalty management functions to you, then you must submit a delegation proposal to the MMS Associate Director for Minerals Revenue Management. MMS will provide you with technical assistance and information to help you prepare your delegation proposal. Your proposal must contain the following minimum information:
(a) The name and title of the State official authorized to submit the delegation proposal and execute the delegation agreement;
(b) The name, address, and telephone number of the State contact for the proposal;
(c) A copy of the legislation, State Attorney General opinion or other document that:
(1) States which State entity or entities are responsible for performing delegated functions, and if more than one entity is delegated such responsibility, the position of the highest ranking State official having ultimate authority over the collection of royalties from leases on Federal lands within the State;
(2) Demonstrates the State's authority to:
(i) Accept a delegation from MMS; and
(ii) Receive State or Federal appropriations to perform delegated functions;
(d) The date you propose to begin performing delegated functions;
(e) A detailed statement of the delegable functions that you propose to perform. For each function, describe the resources available in your State to perform each function, the procedures you will use to perform each function, and how you will assure that you will meet all Federal laws, lease terms, regulations and relevant performance standards. As evidence that you have or will have the resources to perform each delegable function, provide the following information:
(1) A description of the personnel you have available to perform delegated functions, including:
(i) How many persons you will assign full-time and part-time to each delegated function;
(ii) The technical qualifications of the key personnel you will assign to each function, including academic field and degree, professional credentials, and quality and amount of experience with similar functions; and
(iii) Whether these persons are currently State employees. If not, explain how you propose to hire these persons or obtain their services, and when you expect to have those persons available to perform delegated functions;
(2) A description of the facilities you will use to perform delegated functions, including:
(i) Whether you currently have the facilities in which you will physically locate the personnel and equipment you will need to perform the functions you propose to assume. If not, how you propose to acquire such facilities, and when you expect to have such facilities available; and
(ii) How much office space is available;
(3) Describe the equipment you will use to perform delegated functions, including:
(i) Hardware and software you will use to perform each delegated function, including equipment for:
(A) Document processing, including compatibility with MMS automated systems, electronic commerce capabilities, and data storage capabilities;
(B) Accessing reference data;
(C) Contacting production or royalty reporters;
(D) Issuing demands;
(E) Maintaining accounting records;
(F) Performing automated verification;
(G) Maintaining security of confidential and proprietary information; and
(H) Providing data to other Federal agencies;
(ii) Whether you currently have the equipment you will need to perform the functions you propose to assume. If not, how you propose to acquire such equipment and when you expect to have such equipment available;
(f) Your estimates of the costs to fund the following resources necessary to perform the delegation:
(1) Personnel, including hiring, employee salaries and benefits, travel and training;
(2) Facilities, including acquisition, upgrades, operation, and maintenance; and
(3) Equipment, including acquisition, operation, and maintenance;
(g) Your plans to fund the resources under paragraph (f) of this section, including any items you will ask MMS to fund under the delegation agreement;
(h) A statement identifying any areas where State law, including State appropriation law, may limit your ability to perform delegated functions, and an explanation of how you propose to remove any such limitation;
(i) A statement that in accordance with section 203 of the Act (30 U.S.C. 1733) persons who have access to information received under delegated functions are subject to the same provisions of law regarding confidentiality and disclosure of that information as Federal employees. Applicable laws include the Freedom of Information Act (FOIA), the Trade Secrets Act, and relevant Executive Orders. In addition, your statement must acknowledge that all documents produced, received, and maintained as part of any delegation functions are agency records for purposes of FOIA. Therefore, persons who have access to information received under delegated functions may not use such information or provide such information to any other person, including State personnel, for purposes other than performing delegated functions. However, this limitation does not apply if the person submitting the information consents in writing to its use for other State purposes.
[62 FR 43084, Aug. 12, 1997, as amended at 67 FR 19112, Apr. 18, 2002]
§ 227.104
What will MMS do when it receives a State's delegation proposal?
When MMS receives your delegation proposal, it will record the receipt date. MMS will notify you in writing within 15 business days whether your proposal is complete. If it is not complete, MMS will identify any missing items § 227.103 requires. Once you submit all required information, MMS will notify you of the date your application is complete.

Hearing Process
§ 227.105
What are the hearing procedures?
After MMS notifies you that your delegation proposal is complete, MMS will schedule a hearing on your proposal, if MMS determines a hearing is appropriate, as follows:
(a) The MMS Director will appoint a hearing official to conduct one or more public hearings for fact finding regarding your ability to assume the delegated functions requested. The hearing official will not decide whether to approve your delegation request;
(b) The hearing official will contact you about scheduling a hearing date and location;
(c) The MMS will publish notice of the hearing in the Federal Register and other appropriate media within your State;
(d) MMS will publish notice of the proposal in the Federal Register. MMS will also post the proposal on the MMS Website, and upon request, MMS will send a copy of the delegation proposal to the trade associations to distribute to their members, as necessary;
(e) At the hearing, you will have an opportunity to present testimony and written information in support of your proposal;
(f) Other persons may attend the hearing and may present testimony and written information for the record;
(g) MMS will record the hearing;
(h) MMS will maintain a record of all documents related to the proposal process;
(i) After the hearing, MMS may require you to submit additional information in support of your delegation proposal.

Delegation Process
§ 227.106
What statutory requirements must a State meet to receive a delegation?
The MMS Director will decide whether to approve your delegation request and will ask the Secretary of the Interior to concur in the decision. That decision is solely within the MMS Director's and the Secretary's discretion. The MMS Director's decision, which the Secretary concurs in, is the final decision for the Department of the Interior. The MMS Director may approve a State's request for delegation only if, based upon the State's delegation proposal and the hearing record, the MMS Director finds that:
(a) It is likely that the State will provide adequate resources to achieve the purposes of the Act;
(b) The State has demonstrated that it will effectively and faithfully administer the MMS regulations under the Act in accordance with subsections (c) and (d) of section 205 of the Act;
(c) Such delegation will not create an unreasonable burden on any lessee;
(d) The State agrees to adopt standardized reporting procedures MMS prescribes for royalty and production accounting purposes, unless the State and all affected parties (including MMS) otherwise agree;
(e) The State agrees to follow and adhere to regulations and guidelines MMS issues under the mineral leasing laws regarding valuation of production; and
(f) Where necessary for a State to carry out and enforce a delegated activity, the State agrees to enact such laws and promulgate such regulations as are consistent with relevant Federal laws and regulations.
§ 227.107
When will the MMS Director decide whether to approve a State's delegation proposal?
The MMS Director will decide whether to approve your delegation proposal within 90 days after your delegation proposal is considered complete under § 227.104. MMS may extend the 90-day period with your written consent.
§ 227.108
How will MMS notify a State of its decision?
MMS will notify you in writing of its decision on your delegation proposal. If MMS approves your delegation proposal, then MMS will hold discussions with you to develop a delegation agreement detailing the functions that you will perform, the standards and requirements you must comply with to perform those functions, and any required transition period.
§ 227.109
What if the MMS Director denies a State's delegation proposal?
If the MMS Director denies your delegation proposal, MMS will state the reasons for denial. MMS also will inform you in writing of the conditions you must meet to receive approval. You may submit a new delegation proposal at any time following a denial.
§ 227.110
When and for how long are delegation agreements effective?
(a) Delegation agreements are effective for 3 years from the date the MMS Director signs the delegation agreement. However, during the development of the State's delegation proposal under § 227.108 of this part, MMS, the delegated State, and any other affected person will determine an appropriate transition period for lessees and their designees to modify their systems to comply with any new requirements under a delegation agreement. MMS will publish notice of the effective date of a State's delegation agreement in the Federal Register and that notice will inform lessees and their designees of any transition period. MMS also will post the proposals on the MMS Website at www.mms.gov, and upon request, will send a copy of the delegation proposals to trade associations to distribute to their members.
(b) You may ask MMS to renew the delegation for an additional 3 years no less than 6 months before your 3-year delegation agreement expires. You must submit your renewal request to the MMS Associate Director for Minerals Revenue Management as follows:
(1) If you do not want to change the terms of your delegation agreement for the renewal period, you need only ask to extend your existing agreement for the 3-year renewal period. MMS will not schedule a hearing unless you request one;
(2) If you want to change the terms of your delegation agreement for the renewal period, you must submit a new delegation proposal under this part.
(c) The MMS Director may approve your renewal request only if MMS determines that you are meeting the requirements of the applicable standards and regulations. If the MMS Director denies your renewal request, MMS will state the reasons for denial. MMS also will inform you in writing of the conditions you must meet to receive approval. You may submit a new renewal request any time after denial.
(d) After the 3-year renewal period for your delegation agreement ends, if you wish to continue performing one or more delegated functions, you must request a new delegation agreement from MMS under this part. MMS will schedule a hearing on your request, if MMS determines a hearing is appropriate. As part of the decision whether to approve your request for a new delegation, the MMS Director will consider whether you are meeting the requirements of the applicable standards and regulations under your existing delegation agreement.
(e) If you do not request a hearing under paragraphs (b)(1) or (d) of this section, any other affected person may submit a written request for a hearing under those paragraphs to the MMS Associate Director for Minerals Revenue Management.
[62 FR 43084, Aug. 12, 1997, as amended at 67 FR 19112, Apr. 18, 2002]

Existing Delegations
§ 227.111
Do existing delegation agreements remain in effect?
This section explains your options if you have a delegation agreement in effect on the effective date of this regulation.
(a) If you do not want to perform any royalty management functions in addition to those authorized under your existing agreement, you may continue your existing agreement until its expiration date. Before the agreement expires, if you wish to continue to perform one or more of the delegated functions you performed under the expired agreement, you must request a new delegation agreement meeting the requirements of this part and the applicable standards.
(b) If you want to perform royalty management functions in addition to those authorized under your existing agreement, you must request a new delegation agreement under this part.
(c) MMS may extend any delegation agreement in effect on the effective date of this regulation for up to 3 years beyond the date it is due to expire.

Compensation
§ 227.112
What compensation will a State receive to perform delegated functions?
You will receive compensation for your costs to perform each delegated function subject to the following conditions:
(a) Compensation for costs is subject to Congressional appropriations;
(b) Compensation may not exceed the reasonably anticipated expenditures that MMS would incur to perform the same function;
(c) The cost for which you request compensation must be directly related to your performance of a delegated function and necessary for your performance of that delegated function;
(d) At a minimum, you must provide vouchers detailing your expenditures quarterly during the fiscal year. However, you may agree to provide vouchers on a monthly basis in your delegation agreement;
(e) You must maintain adequate books and records to support your vouchers;
(f) MMS will pay you quarterly or monthly during the fiscal year as stated in your delegation agreement; and
(g) MMS may withhold compensation to you for your failure to properly perform any delegated function as provided in section 227.801 of this part.

States' Responsibilities To Perform Delegated Functions
§ 227.200
What are a State's general responsibilities if it accepts a delegation?
For each delegated function you perform, you must:
(a) Operate in compliance with all Federal laws, regulations, and Secretarial and MMS determinations and orders relating to calculating, reporting, and paying mineral royalties and other revenues. You must seek information or guidance from MMS regarding new, complex, or unique issues. If MMS determines that written guidance or interpretation is appropriate, MMS will provide the guidance or interpretation in writing to you and you must follow the interpretation or guidance given;
(b) Comply with Generally Accepted Accounting Principles (GAAP). You must:
(1) Provide complete disclosure of financial results of activities;
(2) Maintain correct and accurate records of all mineral-related transactions and accounts;
(3) Maintain effective controls and accountability;
(4) Maintain a system of accounts that includes a comprehensive audit trail so that all entries may be traced to one or more source documents; and
(5) Maintain adequate royalty and production information for royalty management purposes;
(c) Assist MMS in meeting the requirements of the Government Performance and Results Act (GPRA) as well as assisting in developing and endeavoring to comply with the MMS Strategic Plan and Performance Measurements;
(d) Maintain all records you obtain or create under your delegated function, such as royalty reports, production reports, and other related information. You must maintain such records in a safe, secure manner, including taking appropriate measures for protecting confidential and proprietary information and assisting MMS in responding to Freedom of Information Act requests when necessary. You must maintain such records for at least 7 years;
(e) Provide reports to MMS about your activities under your delegated functions. MMS will specify in your delegation agreement what reports you must submit and how often you must submit them. At a minimum, you must provide periodic statistical reports to MMS summarizing the activities you carried out, such as:
(1) Production and royalty reports processed;
(2) Erroneous reports corrected;
(3) Results of automated verification findings;
(4) Number of audits performed; and
(5) Enforcement documents issued.
(f) Assist MMS in maintaining adequate reference, royalty, and production databases as provided in the Standards issued under § 227.201 of this part and the delegation agreement;
(g) Develop annual work plans that:
(1) Specify the work you will perform for each delegated function; and
(2) Identify the resources you will commit to perform each delegated function;
(h) Help MMS respond to requests for information from other Federal agencies, Congress, and the public;
(i) Cooperate with MMS's monitoring of your delegated functions; and
(j) Comply with the Standards as required under § 227.201 of this part.
§ 227.201
What standards must a State comply with for performing delegated functions?
(a) If MMS delegates royalty management functions to you, you must comply with the Standards. The Standards explain how you must carry out the activities under each of the delegable functions.
(b) Your delegation agreement may include additional standards specifically applicable to the functions delegated to you.
(c) Failure to comply with your delegation agreement, the Standards, or any of the specific standards and requirements in the delegation agreement, is grounds for termination of all or part of your delegation agreement, or other actions as provided under §§ 227.801 and 227.802.
(d) MMS may revise the Standards and will provide notice of those changes in the Federal Register. You must comply with any changes to the Standards.
§ 227.300
What audit functions may a State perform?
An audit consists of an examination of records to verify that royalty reports and payments accurately reflect actual production, sales, revenues and costs, and compliance with Federal statutes, regulations, lease terms, and MMS policy determinations.
(a) If you request delegation of audit functions, you must perform at least the following:
(1) Submitting requests for records;
(2) Examining royalty and production reports;
(3) Examining lessee production and sales records, including contracts, payments, invoices, and transportation and processing costs to substantiate production and royalty reporting;
(4) Providing assistance to MMS for appealed demands or orders, including preparing field reports, performing remanded actions, modifying orders, and providing oral and written briefing and testimony as expert witnesses.
(b) If necessary for a particular audit, you may also perform any of the following:
(1) Issuing engagement letters;
(2) Arranging for entrance conferences;
(3) Scheduling site visits; and
(4) Issuing record releases and audit closure letters; and
(5) Holding closeout conferences.
§ 227.301
What are a State's responsibilities if it performs audits?
If you perform audits you must:
(a) Comply with the MMS Audit Procedures Manual and the Government Auditing Standards issued by the Comptroller General of the United States;
(b) Follow the MMS Annual Audit Work Plan and 5-year Audit Strategy, which MMS will develop in consultation with States having delegated audit authority;
(c) Agree to undertake special audit initiatives MMS identifies targeting specific royalty issues, such as valuation or volume determinations;
(d) Prepare, construct, or compile audit work papers under the appropriate procedures, manuals, and guidelines;
(e) Prepare and submit MMS Audit Work Plans. You may modify your Audit Work Plans with MMS approval; and
(f) Comply with procedures for appealed demands or orders, including meeting timeframes, supplying information, and using the appropriate format.
§ 227.400
What functions may a State perform in processing production reports or royalty reports?
Production reporters or royalty reporters provide production, sales, and royalty information on mineral production from leases that must be collected, analyzed, and corrected.
(a) If you request delegation of either production report or royalty report processing functions, you must perform at least the following:
(1) Receiving, identifying, and date stamping production reports or royalty reports;
(2) Processing production or royalty data to allow entry into a data base;
(3) Creating copies of reports by means such as electronic imaging;
(4) Timely transmitting production report or royalty report data to MMS and other affected Federal agencies as provided in your delegation agreement and the Standards;
(5) Providing training and assistance to production reporters or royalty reporters;
(6) Providing production data or royalty data to MMS and other affected Federal agencies; and
(7) Providing assistance to MMS for appealed demands or orders, including meeting timeframes, supplying information, using the appropriate format, performing remanded actions, modifying orders, and providing oral and written briefing and testimony as expert witnesses.
(b) If you request delegation of either production report or royalty report processing functions, or both, you may perform the following functions:
(1) Granting exceptions from reporting and payment requirements for marginal properties; and
(2) Approving alternative royalty and payment requirements for unit agreements and communitization agreements.
(c) You must provide MMS with a copy of any exceptions from reporting and payment requirements for marginal properties and any alternative royalty and payment requirements for unit agreements and communitization agreements you approve.
§ 227.401
What are a State's responsibilities if it processes production reports or royalty reports?
In processing production reports or royalty reports you must:
(a) Process reports accurately and timely as provided in the Standards and your delegation agreement;
(b) Identify and resolve fatal errors to use in subsequent error correction that the State or MMS performs;
(c) Accept multiple forms of electronic media from reporters, as MMS specifies;
(d) Timely transmit required production or royalty data to MMS and other affected Federal agencies;
(e) Access well, lease, agreement, and reporter reference data from MMS and provide updated information to MMS;
(f) For production reports, maintain adequate system software edits to ensure compliance with the provisions of 30 CFR part 210—Forms and Reports, the MMS Minerals Production Reporter Handbook, any interagency memorandum of understanding to which MMS is a party, and the Standards;
(g) For royalty reports, maintain adequate system software edits to ensure compliance with the provisions of 30 CFR part 218, the Oil and Gas Payor Handbook, Volume II, “Dear Payor” letters, and the Standards; and
(h) Comply with the procedures for appealed demands or orders, including meeting timeframes, supplying information, and using the appropriate format.
[62 FR 43084, Aug. 12, 1997, as amended at 67 FR 19112, Apr. 18, 2002; 73 FR 15898, Mar. 26, 2008]
§ 227.500
What functions may a State perform to ensure that reporters correct erroneous report data?
Production data and royalty data must be edited to ensure that what is reported is correct, that disbursement is made to the proper recipient, and that correct data are used for other functions, such as automated verification and audits. If you request delegation of error correction functions for production reports or royalty reports, or both, you must perform at least the following:
(a) Correcting all fatal errors and assigning appropriate confirmation indicators;
(b) Verifying whether production reports are missing;
(c) Contacting production reporters or royalty reporters about missing reports and resolving exceptions;
(d) Documenting all corrections made, including providing production reporters or royalty reporters with confirmation reports of any changes;
(e) Providing training and assistance to production reporters or royalty reporters;
(f) Issuing notices, orders to report, and bills as needed, including, but not limited to, imposing assessments on a person who chronically submits erroneous reports; and
(g) Providing assistance to MMS for appealed demands or orders, including preparing field reports, performing remanded actions, modifying orders, and providing oral and written briefing and testimony as expert witnesses.
§ 227.501
What are a State's responsibilities to ensure that reporters correct erroneous data?
To ensure the correction of erroneous data, you must:
(a) Ensure compliance with the provisions of 30 CFR parts 216 and 218, any applicable handbook specified under 30 CFR 227.401 (f) and (g), interagency memorandums of understanding to which MMS is a party, and the Standards;
(b) Ensure that reporters accurately and timely correct all fatal errors as designated in the Standards. These errors include, for example, invalid or incorrect reporter/payor codes, incorrect lease/agreement numbers, and missing data fields;
(c) Submit accepted and corrected lines to MMS to allow processing in a timely manner as provided in the Standards and 30 CFR part 219; and
(d) Comply with the procedures for appealed demands or orders, including meeting timeframes, supplying information, and using the appropriate format.
[62 FR 43064, Aug. 12, 1997, as amended at 67 FR 19112, Apr. 18, 2002]
§ 227.600
What automated verification functions may a State perform?
Automated verification involves systematic monitoring of production and royalty reports to identify and resolve reporting or payment discrepancies. States may perform the following:
(a) Automated comparison of sales volumes reported by royalty reporters to sales and transfer volumes reported by production reporters. If you request delegation of automated comparison of sales and production volumes, you must perform at least the following functions:
(1) Performing an initial sales volume comparison between royalty and production reports;
(2) Performing subsequent comparisons when reporters adjust royalty or production reports;
(3) Checking unit prices for reasonable product valuation based on reference price ranges MMS provides;
(4) Resolving volume variances using written correspondence, telephone inquiries, or other media;
(5) Maintaining appropriate file documentation to support case resolution; and
(6) Issuing orders to correct reports or payments;
(b) Any one or more of the following additional automated verification functions:
(1) Verifying compliance with lease financial terms, such as payment of rent, minimum royalty, and advance royalty;
(2) Identifying and resolving improper adjustments;
(3) Identifying late payments and insufficient estimates, including calculating interest owed to MMS and verifying payor-calculated interest owed to MMS;
(4) Calculating interest due to a lessee or its designee for an adjustment or refund, including identifying overpayments and excessive estimates;
(5) Verifying royalty rates; and
(6) Verifying compliance with transportation and processing allowance limitations;
(c) Issuing notices and bills associated with any of the functions under paragraphs (a) and (b) of this section; and
(d) Providing assistance to MMS for any of these delegated functions on appealed demands or orders, including meeting timeframes, supplying information, using the appropriate format, taking remanded actions, modifying orders, and providing oral and written briefing and testimony as expert witnesses.
§ 227.601
What are a State's responsibilities if it performs automated verification?
To perform automated verification of production reports or royalty reports, you must:
(a) Verify through research and analysis all identified exceptions and prepare the appropriate billings, assessment letters, warning letters, notification letters, Lease Problem Reports, other internal forms required, and correspondence required to perform any required follow-up action for each function, as specified in the Standards or your delegation agreement;
(b) Resolve and respond to all production reporter or royalty reporter inquiries;
(c) Maintain all documentation and logging procedures as specified in the Standards or your delegation agreement;
(d) Access well, lease, agreement, and production reporter or royalty reporter reference data from MMS and provide updated information to MMS; and
(e) Comply with procedures for appealed demands and orders, including meeting time frames, supplying information, and using the appropriate format.
§ 227.700
What enforcement documents may a State issue in support of its delegated function?
This section explains what enforcement actions you may take as part of your delegated functions.
(a) You may issue demands, subpoenas, and orders to perform restructured accounting, including related notices to lessees and their designees. You also may enter into tolling agreements under section 15(d)(1) of the Act, 30 U.S.C. 1725(d)(1).
(b) When you issue any enforcement document you must comply with the requirements of section 115 of the Act, 30 U.S.C. 1725.
(c) When you issue a demand or enter into a tolling agreement under section 15(d)(1) of the Act, 30 U.S.C. 1725(d)(1), the highest State official having ultimate authority over the collection of royalties or the State official to whom that authority has been delegated must sign the demand or tolling agreement.
(d) When you issue a subpoena or order to perform a restructured accounting you must:
(1) Coordinate with MMS to ensure identification of issues that may concern more than one State before you issue subpoenas and orders to perform restructured accounting; and
(2) Ensure that the highest State official having ultimate authority over the collection of royalties signs any subpoenas and orders to perform restructured accounting, as required under section 115 of the Act, 30 U.S.C. 1725. This official may not delegate signature authority to any other person.

Performance Review
§ 227.800
How will MMS monitor a State's performance of delegated functions?
This section explains MMS's procedures for monitoring your performance of any of your delegated functions.
(a) A monitoring team of MMS officials will annually review your performance of the delegated functions and compliance with your delegation agreement, the Standards, and 30 U.S.C. 1735, including conducting fiscal examination to verify your costs for reimbursement.
(b) The monitoring team also will:
(1) Periodically review your statistical reports required under § 227.200(e) to verify your accuracy, timeliness, and efficiency;
(2) Check for timely transmittal of production report or royalty report information to MMS and other affected agencies, as applicable, to allow for proper disbursement of funds and processing of information;
(3) Coordinate on-site visits and Office of the Inspector General, General Accounting Office, and MMS audits of your performance of your delegated functions; and
(4) Maintain reports of its monitoring activities.
§ 227.801
What if a State does not adequately perform a delegated function?
If your performance of the delegated function does not comply with your delegation agreement, or the Standards, or if MMS finds that you can no longer meet the statutory requirements under § 227.106, then MMS may:
(a) Notify you in writing of your noncompliance or inability to comply. The notice will prescribe corrective actions you must take, and how long you have to comply. You may ask MMS for an extension of time to comply with the notice. In your extension request you must explain why you need more time; and
(b) If you do not take the prescribed corrective actions within the time that MMS allows in a notice issued under paragraph (a) of this section, then MMS may:
(1) Initiate proceedings under § 227.802 to terminate all or a part of your delegation agreement;
(2) Withhold compensation provided to you under § 227.112; and
(3) Perform the delegated function, before terminating or without terminating your delegation agreement, including, but not limited to, issuing a demand or order to a Federal lessee, or its designee, or any other person when:
(i) Your failure to issue the demand or order would result in an underpayment of an obligation due MMS; and
(ii) The underpayment would go uncollected without MMS intervention.
§ 227.802
How will MMS terminate a State's delegation agreement?
This section explains the procedures MMS will use to terminate all or a part of your delegation agreement:
(a) MMS will notify you in writing that it is initiating procedures to terminate your delegation agreement;
(b) MMS will provide you notice and opportunity for a hearing under § 227.803 of this part;
(c) The MMS Director, with concurrence from the Secretary, will decide whether to terminate your delegation agreement.
(d) After the hearing, MMS may:
(1) Terminate your delegation agreement; or
(2) Allow you 30 days to correct any remaining deficiencies. If you do not correct the deficiency within 30 days, MMS will terminate all or a part of your delegation agreement.
(e) MMS will determine the date your agreement is terminated and will notify you of that date in writing. MMS will determine the termination date based on the number of delegated functions and the impact of the termination on all affected parties.
§ 227.803
What are the hearing procedures for terminating a State's delegation agreement?
(a) The MMS Director will appoint a hearing official to conduct one or more public hearings for fact finding and to determine any actions you must take to correct the noncompliance. The hearing official will not decide whether to terminate your delegation agreement;
(b) The hearing official will contact you about scheduling a hearing date and location;
(c) The hearing official will publish notice of the hearing in the Federal Register and other appropriate media within your State;
(d) At the hearing, you will have an opportunity to present testimony and written information on your ability to perform your delegated functions as required under this part, your delegation agreement, and the Standards;
(e) Other persons may attend the hearing and may present testimony and written information for the record;
(f) MMS will record the hearing;
(g) After the hearing, MMS may require you to submit additional information; and
(h) Information presented at each public hearing will help MMS to determine whether:
(1) You have complied with the terms and conditions of your delegation agreement; or
(2) You have the capability to comply with the requirements under § 227.106 of this part.
§ 227.804
How else may a State's delegation agreement terminate?
You may request MMS to terminate your delegation at any time by submitting your written notice of intent 6 months prior to the date on which you want to terminate. MMS will determine the date your agreement is terminated and will notify you of that date in writing. MMS will determine the termination date based on the number of delegated functions and the impact of the termination on all affected parties.
§ 227.805
How may a State obtain a new delegation agreement after termination?
After your delegation agreement is terminated, you may apply again for delegation by beginning with the proposal process under this part.
Pt. 228

PART 228—COOPERATIVE ACTIVITIES WITH STATES AND INDIAN TRIBES

Subpart A—General Provisions
Sec.
228.1
Purpose.
228.2
Policy.
228.3
Limitation on applicability.
228.4
Authority.
228.5
Delegation of authority.
228.6
Definitions.
228.10
Information collection.
Subpart B—Oil and Gas, General [Reserved]

Subpart C—Oil and Gas, Onshore
228.100
Entering into an agreement.
228.101
Terms of agreement.
228.102
Establishment of standards.
228.103
Maintenance of records.
228.104
Availability of information.
228.105
Funding of cooperative agreements.
228.107
Eligible cost of activities.
228.108
Deduction of civil penalties accruing to the State or tribe from the Federal share of a cooperative agreement.

Authority:
Sec. 202, Pub. L. 97-451, 96 Stat. 2457 (30 U.S.C. 1732).

Source:
49 FR 37348, Sept. 21, 1984, unless otherwise noted.

Subpart A—General Provisions
§ 228.1
Purpose.
It is the purpose of cooperative agreements to effectively utilize the capabilities of the States and Indian tribes in developing and maintaining an efficient and effective Federal royalty management system as indicated at 30 U.S.C. 1701.
§ 228.2
Policy.
It shall be the policy of DOI to enter into cooperative agreements with States and Indian tribes to carry out audits and related investigations and enforcement actions whenever a State or tribe initiates a request to enter into an agreement and a finding is made that a State or tribe has the ability to carry out cooperative activities in a timely and efficient manner.
§ 228.3
Limitation on applicability.
As of the effective date of this rule, September 11, 1997, this part does not apply to Federal lands.
[62 FR 43091, Aug. 12, 1997]
§ 228.4
Authority.
The Secretary of the Interior is authorized to enter into cooperative agreements with States and Indian tribes (30 U.S.C. 1732) to share oil or gas royalty management information, and to carry out auditing and related investigation or enforcement activities in cooperation with the Secretary.
§ 228.5
Delegation of authority.
(a) Authority to enter into cooperative agreements to carry out audit and related investigation and enforcement activities with State and tribal governments has been delegated to the Director of the Minerals Management Service (MMS).
(b) Authority to enter into cooperative agreements with State and tribal governments to carry out inspection and related investigation and enforcement activities has been delegated to the Director of the Bureau of Land Management (BLM) and is not covered by this part.
(c) The entry into a cooperative agreement with either MMS or BLM will not affect the ability of a State or Indian tribe to choose to enter into such an agreement with the other agency. A State may enter into a delegation agreement (30 U.S.C. 1735) with MMS to perform certain functions without affecting its ability to enter into a cooperative agreement with either MMS or BLM, or both, to cooperate in the performance of those functions which are not delegated in this part.
§ 228.6
Definitions.
For the purposes of this part, terms shall have the same meaning as in 30 U.S.C. 1702. In addition, the following definition shall apply:
Audit means an examination of the financial accounting and lease related records of the lessee and other interest holders, who by lease or contract pay royalties or are obligated to pay royalties, rents, bonuses or other payments on Federal or Indian leases. An examination is to be conducted in accordance with generally accepted audit standards as adopted by the American Institute of Certified Public Accountants. Activities to be examined which are considered to be an audit function include reconciliation of lease accounts under the Royalty Accounting System; records of lease activities related to Federal leases located within the boundaries of the State entering into a cooperative agreement; records of lease activities related to leases located on Indian lands, and the review and resolution of exceptions processed by the official accounting systems for royalty reporters and payors maintained by the MMS.
[49 FR 37348, Sept. 21, 1984, as amended at 67 FR 19112, Apr. 18, 2002]
§ 228.10
Information collection.
(a) The information collection requirements contained in this part have been approved by OMB under 44 U.S.C. 3501 et seq. and assigned OMB Clearance Number 1010-0087. The information collected will be used to prepare a cooperative agreement with a State or Indian tribe wishing to perform royalty audits. The information should be submitted voluntarily in order to enter into a cooperative agreement authorized by 30 U.S.C. 1732.
(b) Public reporting burden is estimated to average 136 hours for the preparation of the original request for consideration and application to enter into a cooperative agreement. Subsequent requests for renewal of the agreement may require about 40 hours for the preparation of an annual budget and work plan, and an estimated 8 hours per quarter for preparation of a reimbursement voucher and an audit progress report. Send comments regarding this burden estimate or any other aspect of this collection of information, including suggestions for reducing burden, to the Information Collection Clearance Officer, Minerals Management Service, 381 Elden Street, Herndon, Virginia 22070; and to the Office of Information and Regulatory Affairs, Office of Management and Budget, Paperwork Reduction Project 1010-0087, Washington, DC 20503.
[57 FR 41868, Sept. 14, 1992, as amended at 58 FR 64903, Dec. 10, 1993]
Subpart B—Oil and Gas, General [Reserved]

Subpart C—Oil and Gas, Onshore
§ 228.100
Entering into an agreement.
(a) A State or Indian tribe may request the Department to enter into a cooperative agreement by sending a letter from the governor, tribal chairman, or other appropriate official with delegation authority, to the Director of MMS.
(b) The request for an agreement shall be in a format prescribed by MMS and should include at a minimum the following information:
(1) Type of eligible activities to be undertaken.
(2) Proposed term of the agreement.
(3) Evidence that the State or Indian tribe meets, or can meet by the time the agreement is in effect, the standards established by the Secretary for the types of activities to be conducted under the terms of the agreement.
(4) If the State is proposing to undertake activities on Indian lands located within the State, a resolution from the appropriate tribal council indicating their agreement to delegate to the State responsibilities under the terms of the cooperative agreement for activities to be conducted on tribal or allotted land.
(c) The eligible activities to be conducted under the terms of a cooperative agreement may be funded or unfunded by the Department. See § 228.105 of this subpart for funding of cooperative agreements.
[49 FR 37348, Sept. 21, 1984, as amended at 56 FR 10512, Mar. 13, 1991]
§ 228.101
Terms of agreement.
(a) Agreements entered into under this part shall be valid for a period of 3 years and shall be renewable or additional consecutive 3-year periods upon request of the State or Indian tribe which is a party to the agreement.
(b) An agreement may be terminated at any time by mutual agreement and upon any terms and conditions as agreed upon by the parties.
(c) A State or Indian tribe may unilaterally terminate an agreement by giving a 120-day written notice of intent to terminate.
(d) The MMS may commence termination of an agreement by giving a 120-day written notice of intent to terminate. MMS shall provide the State or Indian tribe with the reasons for the proposed termination in writing if the termination is proposed because of alleged deficiencies by the State or Indian tribe in carrying out the provisions of the agreement. The State or Indian tribe will be given 60 days to respond to the notice of deficiencies and to provide a plan for correction of those deficiencies. No final action on termination shall be taken until any submission of the State or Indian tribe provided within the above prescribed 60 days has been reviewed by MMS for content or merit.
(e) Termination of a cooperative agreement shall not bar a later request by a State or Indian tribe to enter into a subsequent cooperative agreement.
§ 228.102
Establishment of standards.
The MMS, after consultation with States and Indian tribes, shall establish standards for carrying out the activities under the provisions of this part. The standards will be incorporated into the agreement and shall be no more stringent than those applicable to similar activities of the MMS. The States and Indian tribes shall coordinate their planned auditing activities with MMS. Where an MMS audit team is permanently assigned to a lessee/payor, contact by State and Indian tribal auditors with the lessee/payor shall be through the MMS auditor in residence.
§ 228.103
Maintenance of records.
(a) The State or Indian tribe entering into a cooperative agreement under this part must retain all records, reports, working papers, and any backup materials for a period specified by MMS. All records and support materials must be available for inspection and review by appropriate personnel of the Department including the Office of the Inspector General.
(b) The State or Indian tribe shall maintain all books and records as may be necessary to assure compliance with the provisions of chapter 1, 48 CFR 31.107 and 48 CFR subpart 31.6 (Contracts with State, local, and federally recognized Indian tribal Governments).
[56 FR 10512, Mar. 13, 1991]
§ 228.104
Availability of information.
(a) Under the provisions of this part, information necessary to carry out the activities authorized under the terms of a cooperative agreement will be provided by DOI to the States and Indian tribes entering into such agreements. The information will consist of data provided from all relevant sources on a lease level basis for leases located within the boundaries of the State or Indian tribe which has entered into the agreement. This information will include any records or data held by the lessee or other person that have not been submitted to MMS, but that affect Federal lease interests and could be required to be submitted under the lease terms or Federal regulations.
(b) None of the provisions of this subpart should be construed as limiting information already being provided to Indian tribes and allottees regarding their lease interests.
(c) Information will be provided by MMS on a monthly basis and will include data on royalties, rents, and bonuses collected on the lease, volumes produced, sales made, value of products disposed of as a sale and used as a basis for royalty calculation, and other information necessary to allow the State or tribe to carry out its responsibilities under the cooperative agreement.
(d) Proprietary data that is made available to a State or tribe under provisions of 30 U.S.C. 1733 shall be subject to the constraints of 18 U.S.C. 1905. To receive proprietary data, the State or tribe must—
(1) Demonstrate what audit, investigation, or litigation under provisions of 30 U.S.C. 1734 is planned for or underway for which this data is essential;
(2) Demonstrate why this particular data is necessary; and
(3) Agree to safeguard proprietary data as provided.
§ 228.105
Funding of cooperative agreements.
(a)(1) The Department may, under the terms of the cooperative agreement, reimburse the State or Indian tribe up to 100 percent of the costs of eligible activities. Eligible activities will be agreed upon annually upon the submission and approval of a workplan and funding requirement.
(2) A cooperative agreement may be entered into with a State or Indian tribe, upon request, without a requirement for reimbursement of costs by the Department.
(b) All cooperative agreements under this part are subject to annual funding and the availability of appropriations specifically designated for the purpose of this part.
(c) The State or Indian tribe shall submit a voucher for reimbursement of eligible costs incurred within 30 days of the end of each calendar quarter. The State or Indian tribe must provide the Department a summary of costs incurred, for which the State or Indian tribe is seeking reimbursement, with the voucher.
[49 FR 37348, Sept. 21, 1984, as amended at 56 FR 10512, Mar. 13, 1991]
§ 228.107
Eligible cost of activities.
(a) If a cooperative agreement provides for Federal funding, only costs directly associated with eligible activities undertaken by the State or Indian tribe under the terms of a cooperative agreement will be eligible for reimbursement. Costs of services or activities which cannot be directly related to the support of activities specified in the agreement will not be eligible for Federal funding or for inclusion in the State's share or in the Indian tribe's share of funding that may be established in the agreement.
(b) Eligible costs are the cost of salaries and benefits associated with technical, support, and clerical personnel engaged in eligible activities; direct cost of travel, rentals, and other normal administrative activities in direct support of the project or projects; basic and specialized training for State and tribal participants; and cost of any contractual services which can be shown to be in direct support of the activities covered by the agreement. Each cooperative agreement shall contain detailed schedules identifying those activities and costs which qualify for funding and the procedures, timing, and mechanics for implementing Federal funding.
[49 FR 37348, Sept. 21, 1984, as amended at 56 FR 10512, Mar. 13, 1991]
§ 228.108
Deduction of civil penalties accruing to the State or tribe from the Federal share of a cooperative agreement.
As provided at 30 U.S.C. 1736, 50 percent of any civil penalty collected as a result of activities under a cooperative agreement will be shared with the State or Indian tribe performing the cooperative agreement; however, the amount of the civil penalty shared will be deducted from any Federal funding owed under that cooperative agreement. MMS shall maintain records of civil penalties collected and distributed to the States and tribes involved in cooperative agreements. Each quarterly payment of the Federal share of a cooperative agreement will be reduced by the amount of the civil penalties paid to the State or tribe during the prior quarter.
Pt. 229

PART 229—DELEGATION TO STATES

Subpart A—General Provisions
Sec.
229.1
Purpose.
229.2
Policy.
229.3
Limitation on applicability.
229.4
Authority.
229.6
Definitions.
229.10
Information collection requirements.
Subpart B—Oil and Gas, General [Reserved]

Subpart C—Oil and Gas, Onshore

Administration of Delegations
229.100
Authorities and responsibilities subject to delegation.
229.101
Petition for delegation.
229.102
Fact-finding and hearings.
229.103
Duration of delegations; termination of delegations.
229.104
Terms of delegation of authority.
229.105
Evidence of Indian agreement to delegation.
229.106
Withdrawal of Indian lands from delegated authority.
229.107
Disbursement of revenues.
229.108
Deduction of civil penalties accruing to the State or tribe under the delegation of authority.
229.109
Reimbursement for costs incurred by a State under the delegation of authority.
229.110
Examination of the State activities under delegation.
229.111
Materials furnished to States necessary to perform delegation.

Delegation Requirements
229.120
Obtaining regulatory and policy guidance.
229.121
Recordkeeping requirements.
229.122
Coordination of audit activities.
229.123
Standards for audit activities.
229.124
Documentation standards.
229.125
Preparation and issuance of enforcement documents.
229.126
Appeals.
229.127
Reports from States.

Authority:
30 U.S.C. 1735.

Subpart A—General Provisions

Source:
49 FR 37350, Sept. 21, 1984, unless otherwise noted.
§ 229.1
Purpose.
The purpose of this part is to promote the effective utilization of the capabilities of the States in developing and maintaining an efficient and effective Federal royalty management system.
§ 229.2
Policy.
It shall be the policy of the Department of the Interior (DOI) to honor any properly made petition from the Chief Executive or other appopriate official of a State seeking delegation of authority under the provisions of 30 U.S.C. 1735 and to make a delegation to conduct audits and related investigations when the Secretary finds that the provisions of 30 U.S.C. 1735 have been complied with or can be complied with by a State seeking the delegation.
§ 229.3
Limitation on applicability.
As of the effective date of this rule, September 11, 1997, this part does not apply to Federal lands.
[62 FR 43091, Aug. 12, 1997]
§ 229.4
Authority.
The Secretary of the DOI is authorized under provisons of 30 U.S.C. 1735 to delegate authority to States to conduct audits and related investigations with respect to all Federal lands within a State, and to those Indian lands to which a State has received permission from the respective Indian tribe(s) or allottee(s) to carry out audit activities under a delegation from the Secretary.
§ 229.6
Definitions.
The definitions contained in 30 U.S.C. 1702 and in part 228 of this chapter apply to the activities carried out under the provisions of this part.
§ 229.10
Information collection requirements.
The information collection requirements contained in this part do not require approval by the Office of Management and Budget under 44 U.S.C. 3501 et seq., because there are fewer than 10 respondents annually.
Subpart B—Oil and Gas, General [Reserved]

Subpart C—Oil and Gas, Onshore

Authority:
The Federal Oil and Gas Royalty Management Act of 1982 (30 U.S.C. 1701 et seq.).

Administration of Delegations
§ 229.100
Authorities and responsibilities subject to delegation.
(a) All or part of the following authorities and responsibilities of the Secretary under the Act may be delegated to a State authority:
(1) Conduct of audits related to oil and gas royalty payments made to the MMS which are attributable to leased Federal or Indian lands within the State. Delegations with respect to any Indian lands require the written permission, subject to the review of the MMS, of the affected Indian tribe or allottee.
(2) Conduct of investigations related to oil and gas royalty payments made to the MMS which are attributable to leased Federal lands or Indian lands within the State. Delegation with respect to any Indian lands require the written permission, subject to the review of the MMS, of the affected Indian tribe or allottee. No investigation will be initiated without the specific approval of the MMS or the Secretary's designee and in accordance with the Departmental Manual.
(b) The following authorities and responsibilities are specifically reserved to the MMS and are not delegable under these regulations:
(1) Enforcement actions to assess and collect additional royalties identified as a consequence of audits, inspections, and investigations. These include all actions related to resolution of royalty obligations so identified, and the establishment and maintenance of payment performance bonds which may be required during the resolution process.
(2) Enforcement actions to collect civil penalties and interest charges related to findings of audits, inspections, and investigations.
(3) Administration of all appeals and all actions of the Department related to administrative and judicial litigation.
(4) Issuance of subpoenas.
(c) The provisions of this section do not limit the authority provided to the States by section 204 of the Act.
[49 FR 40026, Oct. 12, 1984]
§ 229.101
Petition for delegation.
(a) The governor or other authorized official of any State which contains Federal oil and gas leases, or Indian oil and gas leases where the Indian tribe and allottees have given the State an affirmative indication of their desire for the State to undertake certain royalty management-related activities on their lands, may petition the Secretary to assume responsibilities to conduct audits and related investigations of royalty related matters affecting Federal or Indian oil and gas leases within the State.
(b) A State may enter into a delegation of authority under this part without affecting a State's ability to enter into a cooperative agreement under Part 228 of this chapter.
(c) The Secretary shall carry out all factfinding and hearings he may decide are necessary in order to approve or disapprove the petition.
(d) In the event that the Secretary denies the petition, the Secretary must provide the State with the specific reasons for denial of the petition. The State will then have 60 days to either contest or correct specific deficiencies and to reapply for a delegation of authority.
[49 FR 37350, Sept. 21, 1984. Redesignated and amended at 49 FR 40025, Oct. 12, 1984]
§ 229.102
Fact-finding and hearings.
(a) Upon receipt of a petition for delegation from a State, the Secretary shall appoint a representative to conduct a hearing or hearings to carry out factfinding and determine the ability of the petitioning State to carry out the delegated responsibilities requested in accordance with the provisions of this part.
(b) The Secretary's representative, after proper notice in the Federal Register and other appropriate media within the State, shall hold one or more public hearings to determine whether:
(1) The State has an acceptable plan for carrying out delegated responsibilities and if it is likely that the State will provide adequate resources to achieve the purposes of this part (30 U.S.C. 1735);
(2) The State has the ability to put in place a process within 60 days of the grant of delegation which will assure the Secretary that the functions to be delegated to the State can be effectively carried out;
(3) The State has demonstrated that it will effectively and faithfully administer the rules and regulations of the Secretary in accordance with the requirements at 30 U.S.C. 1735;
(4) The State's plan to carry out the delegated authority will be in accordance with the MMS standards; and
(5) The State's plan to carry out the delegated authority will be coordinated with MMS and the Office of Inspector General audit efforts to eliminate added burden on any lessee or group of lessees operating Federal or Indian oil and gas leases within the State.
(c) A State petitioning for a delegation of authority shall be given the opportunity to present testimony at a public hearing.
[49 FR 37350, Sept. 21, 1984. Redesignated and amended at 49 FR 40025, Oct. 12, 1984]
§ 229.103
Duration of delegations; termination of delegations.
(a) Delegations of authority shall be valid for a period of 3 years and may be renewable for an additional consecutive 3-year period upon request of the State and after the appropriate factfinding required in § 229.101. Delegations are subject to annual funding and the availability of appropriations specifically designated for the purpose of this part.
(b) A delegation of authority may be terminated at any time and upon any terms and conditions as mutually agreed upon by the parties.
(c) A State may terminate a delegation of authority by giving a 120-day written notice of intent to terminate.
(d) The Department may terminate a delegation of authority when it is determined, after opportunity for a hearing, that the State has failed to substantially comply with the provisions of the delegation of authority.
(e) No action to initiate formal hearing proceedings for termination shall be taken until the Department has notified the State in writing of alleged deficiencies and allowed the State 120 days to correct the deficiencies.
(f) Termination of a delegation shall not bar a subsequent request by a State to regain a delegation of authority.
[49 FR 37351, Sept. 21, 1984, as amended at 49 FR 40025, Oct. 12, 1984]
§ 229.104
Terms of delegation of authority.
Each delegation of authority under this part shall be in writing, shall incorporate all the requirements of this part, and shall specifically include:
(a) Terms obligating the State to conduct audit and investigative activities for a specific period of time;
(b) Terms describing the authorities and responsibilities reserved by the MMS, including, but not limited to, those specified under § 229.100;
(c) Terms requiring the State to provide annual audit workplans to include the lease universe by company, or by individual lease accounts, a description of the audit work product(s) to be delivered, and the State resources (staff and otherwise) to be committed to the delegation;
(d) Terms requiring the State to notify the MMS of any changed circumstances which would affect the State's ability to carry out the terms of the delegation;
(e) Terms requiring coordination of delegated activities among the State, the MMS, and the land management agencies responsible for management of the leases included in the audit universe;
(f) Terms requiring the State to maintain and make available to the MMS all audit workpapers, documents, and information gained or developed as a consequence of activities conducted under the delegation;
(g) Terms obligating the State to adhere to all Federal laws, rules and regulations, and Secretarial determinations and orders relating to the calculation, reporting, and payment of oil and gas royalties, in all activities performed under the delegation.
[49 FR 40026, Oct. 12, 1984]
§ 229.105
Evidence of Indian agreement to delegation.
In the case of a State seeking a delegation of authority for Indian lands as well as Federal lands, the State petition to the Secretary must be supported by an appropriate resolution or resolutions of tribal councils joining the State in petitioning for delegation and evidence of the agreement of individual Indian allottees whose lands would be involved in a delegation. Such evidence shall specifically speak to having the State assume delegated responsibility for specific functions related to royalty management activities.
[49 FR 37351, Sept. 21, 1984. Redesignated at 49 FR 40025, Oct. 12, 1984]
§ 229.106
Withdrawal of Indian lands from delegated authority.
If at any time an Indian tribe or an individual Indian allottee determines that it wishes to withdraw from the State delegation of authority in relation to its lands, it may do so by sending a petition of withdrawal to the State. Once the petition has been received, the State shall within 30 days cease all activities being carried out under the delegation of authority on the lands covered by the petition for the tribe or allottee.
[49 FR 37351, Sept. 21, 1984. Redesignated at 49 FR 40025, Oct. 12, 1984]
§ 229.107
Disbursement of revenues.
(a) The additional royalties and late payment charges resulting from State audit work done under a delegation of authority shall be collected by MMS. The State's share of any amounts so collected shall be paid to the State in accordance with the provisions of 30 U.S.C. 191 and part 219 of this chapter.
(b) Amounts collected for Indian leases shall be transferred to the appropriate Indian accounts (designated Treasury accounts) managed by the Bureau of Indian Affairs at the earliest practicable date after such funds are received, but in no case later than the last business day of the month in which such funds are received.
(c) MMS shall provide to the State on a monthly basis, an accounting of collections resulting from audit work and enforcement actions resulting from a delegation of authority. Such accounting will identify collections broken down by royalties, penalties and interest paid.
[49 FR 40026, Oct. 12, 1984]
§ 229.108
Deduction of civil penalties accruing to the State or tribe under the delegation of authority.
Fifty percent of any civil penalty resulting from activities under a delegation of authority shall be shared with the delegated State. However, the amount of the civil penalty shared will be deducted from any Federal funding owed under a delegation of authority under the provisions of 30 U.S.C. 1735. MMS shall maintain records of civil penalties collected and distributed to the States involved in 30 U.S.C. 1735 delegations. Each quarterly payment will be reduced by the amount of the civil penalties paid to the delegated State or tribe during the prior quarter.
[49 FR 37351, Sept. 21, 1984. Redesignated at 49 FR 40025, Oct. 12, 1984]
§ 229.109
Reimbursement for costs incurred by a State under the delegation of authority.
(a) The Department of the Interior (DOI) shall reimburse the State for 100 percent of the direct cost associated with the activities undertaken under the delegation of authority. The State shall maintain books and records in accordance with the standards established by the DOI and will provide the DOI, on a quarterly basis, a summary of costs incurred for which the State is seeking reimbursement. Only costs as defined under the provisions of 30 U.S.C. 1735 are eligible for reimbursement.
(b) The State shall submit a voucher for reimbursement of costs incurred within 30 days of the end of each calendar quarter.
[49 FR 37351, Sept. 21, 1984]
§ 229.110
Examination of the State activities under delegation.
(a) The Department will carry out an annual examination of the State's delegated activities undertaken under the delegation of authority.
(b) The examination required by this section will consist of a management review and a fiscal examination and evaluation to determine—
(1) That activities being carried out by the State under the delegation of authority meet the standards established by the Department and in particular the provisions of 30 U.S.C. 1735; and
(2) That costs incurred by the State under the delegation of authority are eligible for reimbursement by the Department.
[49 FR 37351, Sept. 21, 1984. Redesignated at 49 FR 40025, Oct. 12, 1984]
§ 229.111
Materials furnished to States necessary to perform delegation.
The MMS shall provide to the State all reports, files, and supporting materials within its possession necessary to allow the State to effectively carry out the terms of the delegation specified in § 229.104.
[49 FR 40026, Oct. 12, 1984]

Delegation Requirements

Source:
Sections 229.120 through 229.126 appear at 49 FR 40026, Oct. 12, 1984, unless otherwise noted.
§ 229.120
Obtaining regulatory and policy guidance.
All activities performed by a State under a delegation must be in full accord with all Federal laws, rules and regulations, and Secretarial and agency determinations and orders relating to the calculation, reporting, and payment of oil and gas royalties. In those cases when guidance or interpretations are necessary, the State will direct written requests for such guidance or interpretation to the appropriate MMS officials. All policy and procedural guidance or interpretation provided by the MMS shall be in writing and shall be binding on the State.
§ 229.121
Recordkeeping requirements.
(a) The State shall maintain in a safe and secure manner all records, workpapers, reports, and correspondence gained or developed as a consequence of audit or investigative activities conducted under the delegation. All such records shall be made available for review and inspection upon request by representatives of the Secretary and the Department's Office of Inspector General (OIG).
(b) The State must maintain in a confidential manner all data obtained from DOI sources or from payor or company sources under the delegation which have been deemed “confidential or proprietary” by DOI or a company or payor. In this regard, the State regulatory authority shall be bound by provisions of 30 U.S.C. 1733. MMS shall provide to the State guidelines for determining confidential and proprietary material.
(c) All records subject to the requirements of paragraph (a) must be maintained for a 6-year period measured from the end of the calendar year in which the records were created. All dispositions or records must be with the written approval of the MMS. Upon termination of a delegation, the State shall, within 90 days from the date of termination, assemble all records specified in subsection (a), complete all working paper files in accordance with § 229.124, and transfer such records to the MMS.
(d) The State shall maintain complete cost records for the delegation in accordance with generally accepted accounting principles. Such records shall be in sufficient detail to demonstrate the total actual costs associated with the project and to permit a determination by MMS whether delegation funds were used for their intended purpose. All such records shall be made available for review and inspection upon request by representatives of the Secretary and the Department's Office of Inspector General (OGIG).
§ 229.122
Coordination of audit activities.
(a) Each State with a delegation of authority shall submit annually to the MMS an audit workplan specifically identifying leases, resources, companies, and payors scheduled for audit. This workplan must be submitted 120 days prior to the beginning of each fiscal year. A State may request changes to its workplan (including the companies and leases to be audited) at the end of each quarter of each fiscal year. All requested changes are subject to approval by the MMS and must be submitted in writing.
(b) When a State plans to audit leases of a lessee or royalty payor for which there is an MMS or OIG resident audit team, all audit activities must be coordinated through the MMS or OIG resident supervisor. Such activities include, but are not limited to, issuance of engagement letters, arranging for entrance conferences, submission of data requests, scheduling of audit activities including site visits, submission of issue letters, and closeout conferences.
(c) The State shall consult with the MMS and/or OIG regarding resolution of any coordination problems encountered during the conduct of delegation activities.
§ 229.123
Standards for audit activities.
(a) All audit activities performed under a delegation of authority must be in accordance with the “Standards for Audit of Governmental Organizations, Programs, Activities, and Functions” as issued by the Comptroller General of the United States.
(b) The following audit standards also shall apply to all audit work performed under a delegation of authority.
(1) General standards—(i) Qualifications. The auditors assigned to perform the audit must collectively possess adequate professional proficiency for the tasks required, including a knowledge of accounting, auditing, agency regulations, and industry operations.
(ii) Independence. In all matters relating to the audit work, the audit organization and the individual auditors must be free from personal or external impairments to independence and shall maintain an independent attitude and appearance.
(iii) Due professional care. Due professional care is to be used in conducting the audit and in preparing related reports.
(iv) Quality control. The State governments must institute quality control review procedures to ensure that all audits are performed in conformity with the standards established herein.
(2) Examination and evaluation standards—Standards and requirements for examination and evaluation. Auditors should be alert to situations or transactions that could be indicative of fraud, abuse, or illegal acts with respect to the program. If such evidence exists, auditors should forward this evidence to MMS. The MMS will contact the appropriate Federal law enforcement agencies. The scope of examinations are to be governed by the principle of a justifiable relationship between cost and benefit as determined by the auditor or audit supervisor. Audit procedures should reflect the most efficient method of obtaining the requisite degree of satisfaction. The auditor should determine, to the extent possible, the effect on royalty reporting of the non-arms'-length nature of related party transactions, such as transfers of oil to refinery units affiliated with the producer. A review should be made of compliance with the appropriate laws and regulations applicable to program operations. MMS shall issue guidelines as to the definition and nature of arms'-length and non-arms'-length transactions for use in carrying out delegated audit activities.
(3) Standards of reporting. (i) Written audit reports are to be submitted to the appropriate MMS officials at the end of each field examination.
(ii) A statement in the auditors' report that the examination was made in accordance with the generally accepted program audit standards (including the applicable General Accounting Office (GAO) standards) for royalty compliance audits should be in the appropriate language to indicate that the audit was made in accordance with this statement of standards.
(iii) The auditor's report should contain a statement of positive assurance on those items tested and negative assurance on those items not tested. It should also include all instances of noncompliance and instances or indications of fraud, abuse, or illegal acts found during or in connection with the audit.
(iv) The auditor's report should contain any other material deficiency identified during the audit not covered in paragraph (b)(3)(iii) of this section.
(v) When factors external to the program and to the auditor restrict the audit or interfere with the auditor's ability to form objective opinions and conclusions (such as denial of access to information by a company), the auditor is to notify the MMS. If the limitation is not removed, a description of the matter must be included in the auditor's report. MMS will take all legally enforceable steps necessary to seek information necessary to complete the audit.
(vi) If certain information is prohibited from general disclosure, the auditor's report should state the nature of the information omitted and the requirement that makes the omission necessary.
(vii) Written audit reports are to be prepared in the format prescribed by the MMS.
(viii) In instances where the extent of the audit findings or the amounts involved do not warrant it, a formal audit report need not be issued. In lieu of an audit report, a memorandum of audit findings will be prepared and placed on the case file.
[49 FR 40026, Oct. 12, 1984, as amended at 58 FR 64903, Dec. 10, 1993]
§ 229.124
Documentation standards.
Every audit performed by a State under a delegation of authority must meet certain documentation standards. In particular, detailed workpapers must be developed and maintained.
(a) Workpapers are defined to include all records obtained or created in performing an audit.
(b) Each audit performed varies in scope and detail. As a result, the audit team must determine the best presentation of the workpapers for a particular audit. The following general standards of workpaper preparation are consistent with the goal of achieving proper documentation while maintaining sufficient flexibility.
(1) All relevant information obtained orally must be promptly recorded in writing and incorporated in the workpapers.
(2) Workpapers must be complete and accurate in order to provide support for findings and conclusions.
(3) Workpapers should be clear and understandable without the need for supplementary oral explanations. The information they contain must be clear, complete, and concise, so that anyone using the workpapers will be able to readily determine their purpose, the nature and scope of the work done, and the conclusions drawn.
(4) Workpapers must be legible and as neat as practicable. They must meet standards which allow their use as evidence in judicial and administrative proceedings.
(5) The information contained in workpapers should be restricted to matters which are materially important and relevant to the objectives established for the assignment.
(6) Workpapers must be in sufficient detail to permit a subsequent independent execution of each audit procedure, assuming the target company retains its accounting documentation.
§ 229.125
Preparation and issuance of enforcement documents.
(a) Determinations of additional royalties due resulting from audit activities conducted under a delegation of authority must be formally communicated by the State, to the companies or other payors by an issue letter prior to any enforcement action. The issue letter will serve to ensure that all audit findings are accurate and complete by obtaining advance comments from officials of the companies or payors audited. Issue letters must be prepared in a format specified by the MMS, and transmitted to the company or payor. The company or payor shall be given 30 days from receipt of the letter to respond to the State on the findings contained in the letter.
(b) After evaluating the company or payor's response to the issue letter, the State shall draft a demand letter which will be submitted with supporting workpaper files to the MMS for appropriate enforcement action. Any sustantive revisions to the demand letter will be discussed with the State prior to issuance of the letter. Copies of all enforcement action documents shall be provided to the State by MMS upon their issuance to the company or payor.
§ 229.126
Appeals.
(a) Appeals made pursuant to the rules and procedures at 30 CFR parts 243 and 290 related to demand letters issued by officers of the MMS for additional royalties identified under a delegation of authority shall be filed with the MMS for processing. The State regulatory authority shall, upon the request of the MMS, provide competent and knowledgeable staff for testimony, as well as any required documentation and analyses, in support of the lessor's position during the appeal process.
(b) An affected State, upon the request of the MMS, shall provide expert witnesses from their audit staff for testimony as well as required documentation and analyses to support the Department's position during the litigation of court cases arising from denied appeals. The cost of providing expert witnesses including travel and per diem is reimbursable under the provisions of a delegation of authority, at the Federal Government's existing per diem rates.
§ 229.127
Reports from States.
The State, acting under the authority of the Secretarial delegation, shall submit quarterly reports which will summarize activities carried out by the State during the preceding quarter of the year under the provisions of the delegation. The report shall include:
(a) A statistical summary of the activities carried out, e.g., number of audits performed, accounts reconciled, and other actions taken;
(b) A summary of costs incurred during the previous quarter for which the State is seeking reimbursement; and
(c) A schedule of changes which the State proposes to make from its approved plan.
[49 FR 37351, Sept. 21, 1984. Redesignated at 49 FR 40025, Oct. 12, 1984]
PART 230—RECOUPMENTS AND REFUNDS [RESERVED]
PART 232—INTEREST PAYMENTS [RESERVED]
PART 233—ESCROW AND INVESTMENTS [RESERVED]
PART 234—BONDING—PAYMENT LIABILITY [RESERVED]
Pt. 241

PART 241—PENALTIES
Subpart A—General Provisions [Reserved]

Subpart B—Penalties for Federal and Indian Oil and Gas Leases

Definitions
Sec.
241.50
What definitions apply to this subpart?

Penalties after a Period To Correct
241.51
What may MMS do if I violate a statute, regulation, order, or lease term relating to a Federal or Indian oil and gas lease?
241.52
What if I correct the violation?
241.53
What if I do not correct the violation?
241.54
How may I request a hearing on the record on a Notice of Noncompliance?
241.55
Does my request for a hearing on the record affect the penalties?
241.56
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
241.60
May I be subject to penalties without prior notice and an opportunity to correct?
241.61
How will MMS inform me of violations without a period to correct?
241.62
How may I request a hearing on the record on a Notice of Noncompliance regarding violations without a period to correct?
241.63
Does my request for a hearing on the record affect the penalties?
241.64
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
241.70
How does MMS decide what the amount of the penalty should be?
241.71
Does the penalty affect whether I owe interest?
241.72
How will the Office of Hearings and Appeals conduct the hearing on the record?
241.73
How may I appeal the Administrative Law Judge's decision?
241.74
May I seek judicial review of the decision of the Interior Board of Land Appeals?
241.75
When must I pay the penalty?
241.76
Can MMS reduce my penalty once it is assessed?
241.77
How may MMS collect the penalty?

Criminal Penalties
241.80
May the United States criminally prosecute me for violations under Federal and Indian oil and gas leases?
Subpart C—Federal and Indian Oil [Reserved]
Subpart D—Federal and Indian Gas [Reserved]
Subpart E—Solid Minerals, General [Reserved]
Subpart F—Coal [Reserved]
Subpart G—Other Solid Minerals [Reserved]
Subpart H—Geothermal [Reserved]
Subpart I—OCS Sulfur [Reserved]

Authority:
25 U.S.C. 396 et seq., 396a et seq., 2101 et seq.; 30 U.S.C. 181 et seq., 351 et seq., 1001 et seq., 1701 et seq.; 43 U.S.C. 1301 et seq., 1331 et seq., 1801 et seq.
Subpart A—General Provisions [Reserved]

Subpart B—Penalties for Federal and Indian Oil and Gas Leases

Source:
64 FR 26251, May 13, 1999, unless otherwise noted.

Definitions
§ 241.50
What definitions apply to this subpart?
The terms used in this subpart have the same meaning as in 30 U.S.C. 1702.

Penalties After a Period To Correct
§ 241.51
What may MMS do if I violate a statute, regulation, order, or lease term relating to a Federal or Indian oil and gas lease?
(a) If we believe that you have not followed any requirement of a statute, regulation, order, or terms of a lease for any Federal or Indian oil or gas lease, we may send you a Notice of Noncompliance telling you what the violation is and what you need to do to correct it to avoid civil penalties under 30 U.S.C. 1719(a) and (b).
(b) We will serve the Notice of Noncompliance by registered mail or personal service using your address of record as specified under subpart H of part 218.
[64 FR 26251, May 13, 1999, as amended at 71 FR 51752, Aug. 31, 2006]
§ 241.52
What if I correct the violation?
The matter will be closed if you correct all of the violations identified in the Notice of Noncompliance within 20 days after you receive the Notice (or within a longer time period specified in the Notice).
§ 241.53
What if I do not correct the violation?
(a) We may send you a Notice of Civil Penalty if you do not correct all of the violations identified in the Notice of Noncompliance within 20 days after you receive the Notice of Noncompliance (or within a longer time period specified in that Notice). The Notice of Civil Penalty will tell you how much penalty you must pay. The penalty may be up to $500 per day, beginning with the date of the Notice of Noncompliance, for each violation identified in the Notice of Noncompliance for as long as you do not correct the violations.
(b) If you do not correct all of the violations identified in the Notice of Noncompliance within 40 days after you receive the Notice of Noncompliance (or 20 days following the expiration of a longer time period specified in that Notice), we may increase the penalty to up to $5,000 per day, beginning with the date of the Notice of Noncompliance, for each violation for as long as you do not correct the violations.
§ 241.54
How may I request a hearing on the record on a Notice of Noncompliance?
You may request a hearing on the record on a Notice of Noncompliance by filing a request within 30 days of the date you received the Notice of Noncompliance with the Hearings Division (Departmental), Office of Hearings and Appeals, U.S. Department of the Interior, 801 North Quincy Street, Arlington, Virginia 22203. You may do this regardless of whether you correct the violations identified in the Notice of Noncompliance.
[64 FR 26251, May 13, 1999, as amended at 67 FR 19112, Apr. 18, 2002]
§ 241.55
Does my request for a hearing on the record affect the penalties?
(a) If you do not correct the violations identified in the Notice of Noncompliance, the penalties will continue to accrue even if you request a hearing on the record.
(b) You may petition the Hearings Division (Departmental) of the Office of Hearings and Appeals, to stay the accrual of penalties pending the hearing on the record and a decision by the Administrative Law Judge under § 241.72.
(1) You must file your petition within 45 calendar days of receiving the Notice of Noncompliance.
(2) To stay the accrual of penalties, you must post a bond or other surety instrument using the same standards and requirements as prescribed in 30 CFR part 243, subpart B, or demonstrate financial solvency using the same standards and requirements as prescribed in 30 CFR part 243, subpart C, for the principal amount of any unpaid amounts due that are the subject of the Notice of Noncompliance, including interest thereon, plus the amount of any penalties accrued before the date a stay becomes effective.
(3) The Hearings Division will grant or deny the petition under 43 CFR 4.21(b).
§ 241.56
May I request a hearing on the record regarding the amount of a civil penalty if I did not request a hearing on the Notice of Noncompliance?
(a) You may request a hearing on the record to challenge only the amount of a civil penalty when you receive a Notice of Civil Penalty, if you did not previously request a hearing on the record under § 241.54. If you did not request a hearing on the record on the Notice of Noncompliance under § 241.54, you may not contest your underlying liability for civil penalties.
(b) You must file your request within 10 days after you receive the Notice of Civil Penalty with the Hearings Division (Departmental), Office of Hearings and Appeals, U.S. Department of the Interior, 801 North Quincy Street, Arlington, Virginia 22203.
[64 FR 26251, May 13, 1999, as amended at 67 FR 19113, Apr. 18, 2002]

Penalties Without a Period To Correct
§ 241.60
May I be subject to penalties without prior notice and an opportunity to correct?
The Federal Oil and Gas Royalty Management Act sets out several specific violations for which penalties accrue without an opportunity to first correct the violation.
(a) Under 30 U.S.C. 1719(c), you may be subject to penalties of up to $10,000 per day per violation for each day the violation continues if you:
(1) Knowingly or willfully fail to make any royalty payment by the date specified by statute, regulation, order or terms of the lease;
(2) Fail or refuse to permit lawful entry, inspection, or audit; or
(3) Knowingly or willfully fail or refuse to notify the Secretary, within 5 business days after any well begins production on a lease site or allocated to a lease site, or resumes production in the case of a well which has been off production for more than 90 days, of the date on which production has begun or resumed.
(b) Under 30 U.S.C. 1719(d), you may be subject to civil penalties of up to $25,000 per day for each day each violation continues if you:
(1) Knowingly or willfully prepare, maintain, or submit false, inaccurate, or misleading reports, notices, affidavits, records, data, or other written information;
(2) Knowingly or willfully take or remove, transport, use or divert any oil or gas from any lease site without having valid legal authority to do so; or
(3) Purchase, accept, sell, transport, or convey to another person, any oil or gas knowing or having reason to know that such oil or gas was stolen or unlawfully removed or diverted.
§ 241.61
How will MMS inform me of violations without a period to correct?
We will inform you of any violation, without a period to correct, by issuing a Notice of Noncompliance and Civil Penalty explaining the violation, how to correct it, and the penalty assessment. We will serve the Notice of Noncompliance and Civil Penalty by registered mail or personal service using your address of record as specified under subpart H of part 218.
[71 FR 51752, Aug. 31, 2006]
§ 241.62
How may I request a hearing on the record on a Notice of Noncompliance regarding violations without a period to correct?
You may request a hearing on the record of a Notice of Noncompliance regarding violations without a period to correct by filing a request within 30 days after you receive the Notice of Noncompliance with the Hearings Division (Departmental), Office of Hearings and Appeals, U.S. Department of the Interior, 801 North Quincy Street, Arlington, Virginia 22203. You may do this regardless of whether you correct the violations identified in the Notice of Noncompliance.
[64 FR 26251, May 13, 1999, as amended at 67 FR 19113, Apr. 18, 2002]
§ 241.63
Does my request for a hearing on the record affect the penalties?
(a) If you do not correct the violations identified in the Notice of Noncompliance regarding violations without a period to correct, the penalties will continue to accrue even if you request a hearing on the record.
(b) You may ask the Hearings Division (Departmental) to stay the accrual of penalties pending the hearing on the record and a decision by the Administrative Law Judge under § 241.72.
(1) You must file your petition within 45 calendar days after you receive the Notice of Noncompliance.
(2) To stay the accrual of penalties, you must post a bond or other surety instrument using the same standards and requirements as prescribed in 30 CFR part 243, subpart B, or demonstrate financial solvency using the same standards and requirements as prescribed in 30 CFR part 243, subpart C, for the principal amount of any unpaid amounts due that are the subject of the Notice of Noncompliance, including interest thereon, plus the amount of any penalties accrued before the date a stay becomes effective.
(3) The Hearings Division will grant or deny the petition under 43 CFR 4.21(b).
§ 241.64
May I request a hearing on the record regarding the amount of a civil penalty if I did not request a hearing on the Notice of Noncompliance?
(a) You may request a hearing on the record to challenge only the amount of a civil penalty when you receive a Notice of Civil Penalty regarding violations without a period to correct, if you did not previously request a hearing on the record under § 241.62. If you did not request a hearing on the record on the Notice of Noncompliance under § 241.62, you may not contest your underlying liability for civil penalties.
(b) You must file your request within 10 days after you receive Notice of Civil Penalty with the Hearings Division (Departmental), Office of Hearings and Appeals, U.S. Department of the Interior, 801 North Quincy Street, Arlington, Virginia 22203.
[64 FR 26251, May 13, 1999, as amended at 67 FR 19113, Apr. 18, 2002]

General Provisions
§ 241.70
How does MMS decide what the amount of the penalty should be?
We determine the amount of the penalty by considering the severity of the violations, your history of compliance, and if you are a small business.
§ 241.71
Does the penalty affect whether I owe interest?
(a) The penalties under this part are in addition to interest you may owe on any underlying underpayments or unpaid debt.
(b) If you do not pay the penalty by the date required under § 241.75(d), MMS will assess you late payment interest on the penalty amount at the same rate interest is assessed under 30 CFR 218.54.
§ 241.72
How will the Office of Hearings and Appeals conduct the hearing on the record?
If you request a hearing on the record under §§ 241.54, 241.56, 241.62 or 241.64, the hearing will be conducted by a Departmental Administrative Law Judge from the Office of Hearings and Appeals. After the hearing, the Administrative Law Judge will issue a decision in accordance with the evidence presented and applicable law.
§ 241.73
How may I appeal the Administrative Law Judge's decision?
If you are adversely affected by the Administrative Law Judge's decision, you may appeal that decision to the Interior Board of Land Appeals under 43 CFR part 4, subpart E.
§ 241.74
May I seek judicial review of the decision of the Interior Board of Land Appeals?
Under 30 U.S.C. 1719(j), you may seek judicial review of the decision of the Interior Board of Land Appeals. A suit for judicial review in the District Court will be barred unless filed within 90 days after the final order.
§ 241.75
When must I pay the penalty?
(a) You must pay the amount of the Notice of Civil Penalty issued under §§ 241.53 or 241.61, if you do not request a hearing on the record under § 241.54, § 241.56, § 241.62, or § 241.64.
(b) If you request a hearing on the record under § 241.54, § 241.56, § 241.62, or § 241.64, but you do not appeal the determination of the Administrative Law Judge to the Interior Board of Land Appeals under § 241.73, you must pay the amount assessed by the Administrative Law Judge.
(c) If you appeal the determination of the Administrative Law Judge to the Interior Board of Land Appeals, you must pay the amount assessed in the IBLA decision.
(d) You must pay the penalty assessed within 40 days after:
(1) You received the Notice of Civil Penalty, if you did not request a hearing on the record under either § 241.54, § 241.56, § 241.62, or § 241.64;
(2) You received an Administrative Law Judge's decision under § 241.72, if you obtained a stay of the accrual of penalties pending the hearing on the record under § 241.55(b) or § 241.63(b) and did not appeal the Administrative Law Judge's determination to the IBLA under § 241.73;
(3) You received an IBLA decision under § 241.73 if the IBLA continued the stay of accrual of penalties pending its decision and you did not seek judicial review of the IBLA's decision; or
(4) A final non-appealable judgment of a court of competent jurisdiction is entered, if you sought judicial review of the IBLA's decision and the Department or the appropriate court suspended compliance with the IBLA's decision pending the adjudication of the case.
(e) If you do not pay, that amount is subject to collection under the provisions of § 241.77.
§ 241.76
Can MMS reduce my penalty once it is assessed?
Under 30 U.S.C. 1719(g), the Director or his or her delegate may compromise or reduce civil penalties assessed under this part.
§ 241.77
How may MMS collect the penalty?
(a) MMS may use all available means to collect the penalty including, but not limited to:
(1) Requiring the lease surety, for amounts owed by lessees, to pay the penalty;
(2) Deducting the amount of the penalty from any sums the United States owes to you; and
(3) Using judicial process to compel your payment under 30 U.S.C. 1719(k).
(b) If the Department uses judicial process, or if you seek judicial review under § 241.74 and the court upholds assessment of a penalty, the court shall have jurisdiction to award the amount assessed plus interest assessed from the date of the expiration of the 90-day period referred to in § 241.74. The amount of any penalty, as finally determined, may be deducted from any sum owing to you by the United States.

Criminal Penalties
§ 241.80
May the United States criminally prosecute me for violations under Federal and Indian oil and gas leases?
If you commit an act for which a civil penalty is provided at 30 U.S.C. 1719(d) and § 241.60(b), the United States may pursue criminal penalties as provided at 30 U.S.C. 1720, in addition to any authority for prosecution under other statutes.
Subpart C—Federal and Indian Oil [Reserved]
Subpart D—Federal and Indian Gas [Reserved]
Subpart E—Solid Minerals, General [Reserved]
Subpart F—Coal [Reserved]
Subpart G—Other Solid Minerals [Reserved]
Subpart H—Geothermal [Reserved]
Subpart I—OCS Sulfur [Reserved]
PART 242—ORDERS [RESERVED]
Pt. 243

PART 243—SUSPENSIONS PENDING APPEAL AND BONDING—MINERALS REVENUE MANAGEMENT

Subpart A—General Provisions
Sec.
243.1
What is the purpose of this part?
243.2
What leases are subject to this part?
243.3
What definitions apply to this part?
243.4
How do I suspend compliance with an order?
243.5
May another person post a bond or other surety instrument or demonstrate financial solvency on my behalf?
243.6
When must I or another person meet the bonding or financial solvency requirements under this part?
243.7
What must a person do when posting a bond or other surety instrument or demonstrating financial solvency on behalf of an appellant?
243.8
When will MMS suspend my obligation to comply with an order?
243.9
Will MMS continue to suspend my obligation to comply with an order if I seek judicial review in a Federal court?
243.10
When will MMS collect against a bond or other surety instrument or a person demonstrating financial solvency?
243.11
May I appeal the MMS bond-approving officer's determination of my surety amount or financial solvency?
243.12
May I substitute a demonstration of financial solvency for a bond posted before the effective date of this rule?

Subpart B—Bonding Requirements
243.100
What standards must my MMS-specified surety instrument meet?
243.101
How will MMS determine the amount of my bond or other surety instrument?

Subpart C—Financial Solvency Requirements
243.200
How do I demonstrate financial solvency?
243.201
How will MMS determine if I am financially solvent?
243.202
When will MMS monitor my financial solvency?

Authority:
5 U.S.C. 301 et seq.; 25 U.S.C. 396 et seq., 396a et seq., 2101 et seq.; 30 U.S.C. 181 et seq., 351 et seq., 1001 et seq., 1701 et seq.; 31 U.S.C. 9701; 43 U.S.C. 1301 et seq., 1331 et seq., and 1801 et seq.

Source:
64 FR 26254, May 13, 1999, unless otherwise noted.

Subpart A—General Provisions
§ 243.1
What is the purpose of this part?
This part applies to you if you are a lessee or recipient of an order. This part explains:
(a) How you may suspend compliance with an order that you (or your designee if you are a lessee) have appealed under 30 CFR part 290 in effect prior to May 13, 1999 and contained in the 30 CFR, parts 200 to 699, edition revised as of July 1, 1998, or under 30 CFR part 290, subpart b; and
(b) When you or another person acting on your behalf must submit a bond or other surety or demonstrate financial solvency.
§ 243.2
What leases are subject to this part?
This part applies to all Federal mineral leases onshore and on the Outer Continental Shelf (OCS), and to all federally-administered mineral leases on Indian tribal and individual Indian mineral owners' lands.
§ 243.3
What definitions apply to this part?
Assessment means any fee or charge levied or imposed by the Secretary or a delegated State other than:
(1) The principal amount of any royalty, minimum royalty, rental, bonus, net profit share or proceed of sale;
(2) Any interest; or
(3) Any civil or criminal penalty.
Designee means the person designated by a lessee under § 218.52 of this chapter to make all or part of the royalty or other payments due on a lease on the lessee's behalf.
Lessee means any person to whom the United States, or the United States on behalf of an Indian tribe or individual Indian mineral owner, issues a lease, or any person to whom all or part of the lessee's interest or operating rights in a lease has been assigned.
MMS bond-approving officer means the Associate Director for Minerals Revenue Management or an official to whom the Associate Director delegates that responsibility.
MMS-specified surety instrument means an MMS-specified administrative appeal bond, an MMS-specified irrevocable letter of credit, a Treasury book-entry bond or note, or a financial institution book-entry certificate of deposit.
Notice of order means the notice that MMS or a delegated State issues to a lessee that informs the lessee that MMS or the delegated State has issued an order to the lessee's designee.
Order means an order appealable under 30 CFR part 290 in effect prior to May 13, 1999 and contained in the 30 CFR, parts 200 to 699, edition revised as of July 1, 1998, under 30 CFR part 290 subpart B, or under 30 CFR part 208.
Person means any individual, firm, corporation, association, partnership, consortium, or joint venture.
[64 FR 26254, May 13, 1999, as amended at 67 FR 19113, Apr. 18, 2002]
§ 243.4
How do I suspend compliance with an order?
(a) If you timely appeal an order, and if that order or portion of that order:
(1) Requires you to make a payment, and you want to suspend compliance with that order, you must post a bond or other surety instrument or demonstrate financial solvency under this part, except as provided in paragraph (b) of this section; or
(2) Does not require you to make a payment, compliance with that order is suspended when you meet all requirements to file that appeal.
(b) You need not meet the requirements of paragraph (a) of this section if:
(1) The order is an assessment; or
(2) Another person agrees to fulfill these requirements on your behalf under § 243.5.
§ 243.5
May another person post a bond or other surety instrument or demonstrate financial solvency on my behalf?
Any other person, including a designee, payor, or affiliate, may post a bond or other surety instrument or demonstrate financial solvency under this part on behalf of an appellant required to post a bond or other surety instrument under § 243.4(a)(1).
§ 243.6
When must I or another person meet the bonding or financial solvency requirements under this part?
If you must meet the bonding or financial solvency requirements under § 243.4(a)(1), or if another person is meeting your bonding or financial solvency requirements, then either you or the other person must post a bond or other surety instrument or demonstrate financial solvency within 60 days after you receive the order or the Notice of Order.
§ 243.7
What must a person do when posting a bond or other surety instrument or demonstrating financial solvency on behalf of an appellant?
If you assume an appellant's responsibility to post a bond or other surety instrument or demonstrate financial solvency under § 243.5, you:
(a) Must notify MMS in writing at the address specified in § 243.200(a) that you are assuming the appellant's responsibility under this part;
(b) May not assert that you are not otherwise liable for royalties or other payments under 30 U.S.C. 1712(a), or any other theory, as a defense if MMS calls your bond or requires you to pay based on your demonstration of financial solvency; and
(c) May end your voluntarily-assumed responsibility for posting a bond or other surety instrument only after the appellant under this part either:
(1) Pays or posts a bond or other surety instrument; or
(2) Demonstrates financial solvency.
§ 243.8
When will MMS suspend my obligation to comply with an order?
(a) Federal leases.Subject to paragraph (d) of this section, if you appeal an order regarding the payment and reporting of royalties and other payments due from Federal mineral leases onshore or on the Outer Continental Shelf (OCS), and:
(1) If the amount under appeal is less than $10,000 or does not require payment of a specified amount, MMS will suspend your obligation to comply with the order. MMS will use the lease surety posted with the Bureau of Land Management for onshore leases, and MMS for OCS leases, as collateral for the obligation; or
(2) If the amount under appeal is $10,000 or more, MMS will suspend your obligation to comply with that order if you:
(i) Submit an MMS-specified surety instrument under subpart B of this part within a time period MMS prescribes; or
(ii) Demonstrate financial solvency under subpart C.
(b) Indian leases.Subject to paragraph (d) of this section, if you appeal an order regarding the payment and reporting of royalties and other payments due from Indian mineral leases subject to this part, and:
(1) If the amount under appeal is less than $1,000 or does not require payment, MMS will suspend your obligation to comply with the order. MMS will use the lease surety posted with the Bureau of Indian Affairs as collateral for the obligation; or
(2) If the amount under appeal is $1,000 or more, MMS will suspend your obligation to comply with that order if you submit an MMS-specified surety instrument under subpart B of this part within a time period MMS prescribes.
(c) Nothing in this part prohibits you from paying any demanded amount or complying with any other requirement pending appeal. However, voluntarily paying any demanded amount or otherwise complying with any other requirement when suspension of an order is otherwise available under these rules does not create judicially reviewable final agency action under 5 U.S.C. 704.
(d) Regardless of the amount under appeal, MMS may inform you that it will not suspend your obligation to comply with the order under paragraph (a) or (b) of this section because suspension would harm the interests of the United States or the Indian lessor.
§ 243.9
Will MMS continue to suspend my obligation to comply with an order if I seek judicial review in a Federal court?
(a) If you seek judicial review of an IBLA decision or other final action of the Department of the Interior regarding an order, MMS will suspend your obligation to comply with that order pending judicial review if you continue to meet the requirements of this part.
(b) Notwithstanding the provisions of paragraph (a) of this section, MMS may decide that it will not suspend your obligation to comply with an order. MMS will notify you in writing of that decision and the reasons for it.
§ 243.10
When will MMS collect against a bond or other surety instrument or a person demonstrating financial solvency?
(a) This section applies to you if, for an appeal of an order under this part, you:
(1) Maintain a bond or an MMS-specified surety instrument on your own behalf or for another person; or
(2) Have demonstrated financial solvency on your own behalf or for another person.
(b) MMS may initiate collection against the bond or other surety instrument or the person demonstrating financial solvency:
(1) If the MMS Director or the Deputy Commissioner of Indian Affairs decides your appeal adversely to you and you do not pay the amount due or appeal that decision to the IBLA under 43 CFR part 4, subpart E;
(2) If the IBLA, the Director of the Office of Hearings and Appeals, an Assistant Secretary, or the Secretary decides your appeal adversely to you, and you do not pay the amount due or pursue judicial review within 90 days of the decision;
(3) If a court of competent jurisdiction issues a final non-appealable decision adverse to you, and you do not pay the amount due within 30 days of the decision;
(4) If you do not increase the amount of your bond or other surety instrument as required under § 243.101(b), or otherwise fail to maintain an adequate surety instrument in effect, and you do not pay the amount due under the order within 30 days of notice from MMS under § 243.101(b);
(5) If the obligation to comply with an order or decision is not suspended under § 243.8 or § 243.9 and you do not pay the amount required under the order or decision; or
(6) If the MMS bond-approving officer determines that you are no longer financially solvent under § 243.202(c), and you do not pay the order amount or post a bond or other MMS-specified surety instrument under subpart B within 30 days of that determination.
§ 243.11
May I appeal the MMS bond-approving officer's determination of my surety amount or financial solvency?
Any decision on your surety amount under subpart B or your financial solvency under subpart C is final and is not subject to appeal.
§ 243.12
May I substitute a demonstration of financial solvency for a bond posted before the effective date of this rule?
If you appealed an order before June 14, 1999 and you submitted an MMS-specified surety instrument to suspend compliance with that order, you may replace the surety with a demonstration of financial solvency under this part at an administratively convenient time, such as when the surety instrument is due for renewal.

Subpart B—Bonding Requirements
§ 243.100
What standards must my MMS-specified surety instrument meet?
(a) An MMS-specified surety instrument must be in a form specified in MMS instructions. MMS will give you written information and standard forms for MMS-specified surety instrument requirements.
(b) MMS will use a bank-rating service to determine whether a financial institution has an acceptable rating to provide a surety instrument adequate to indemnify the lessor from loss or damage.
(1) Administrative appeal bonds must be issued by a qualified surety company which the Department of the Treasury has approved.
(2) Irrevocable letters of credit or certificates of deposit must be from a financial institution acceptable to MMS with a minimum 1-year period of coverage subject to automatic renewal up to 5 years.
§ 243.101
How will MMS determine the amount of my bond or other surety instrument?
(a) The MMS bond-approving officer may approve your surety if he or she determines that the amount is adequate to guarantee payment. The amount of your surety may vary depending on the form of the surety and how long the surety is effective.
(1) The amount of the MMS-specified surety instrument must include the principal amount owed under the order plus any accrued interest we determine is owed plus projected interest for a 1-year period.
(2) Treasury book-entry bond or note amounts must be equal to at least 120 percent of the required surety amount.
(b) If your appeal is not decided within 1 year from the filing date, you must increase the surety amount to cover additional estimated interest for another 1-year period. You must continue to do this annually on the date your appeal was filed. We will determine the additional estimated interest and notify you of the amount so you can amend your surety instrument.
(c) You may submit a single surety instrument that covers multiple appeals. You may change the instrument to add new amounts under appeal or remove amounts that have been adjudicated in your favor or that you have paid if you:
(1) Amend the single surety instrument annually on the date you filed your first appeal; and
(2) Submit a separate surety instrument for new amounts under appeal until you amend the instrument to cover the new appeals.

Subpart C—Financial Solvency Requirements
§ 243.200
How do I demonstrate financial solvency?
(a) To demonstrate financial solvency under this part, you must submit an audited consolidated balance sheet, and, if requested by the MMS bond-approving officer, up to 3 years of tax returns to the MMS, Debt Collection Section using:
(1) The U.S. Postal Service or private delivery at P.O. Box 5760, MS 3031, Denver, CO 80217-5760; or
(2) Courier or overnight delivery at MS 3031, Denver Federal Center, Bldg. 85, Room A-212, Denver, CO 80225-0165.
(b) You must submit an audited consolidated balance sheet annually, and, if requested, additional annual tax returns on the date MMS first determined that you demonstrated financial solvency as long as you have active appeals, or whenever MMS requests.
(c) If you demonstrate financial solvency in the current calendar year, you are not required to redemonstrate financial solvency for new appeals of orders during that calendar year unless you file for protection under any provision of the U.S. Bankruptcy Code (Title 11 of the United States Code), or MMS notifies you that you must redemonstrate financial solvency.
§ 243.201
How will MMS determine if I am financially solvent?
(a) The MMS bond-approving officer will determine your financial solvency by examining your total net worth, including, as appropriate, the net worth of your affiliated entities.
(b) If your net worth, minus the amount we would require as surety under subpart B for all orders you have appealed is greater than $300 million, you are presumptively deemed financially solvent, and we will not require you to post a bond or other surety instrument.
(c) If your net worth, minus the amount we would require as surety under subpart B for all orders you have appealed is less than $300 million, you must submit the following to the MMS Debt Collection Section by one of the methods in § 243.200(a):
(1) A written request asking us to consult a business-information, or credit-reporting service or program to determine your financial solvency; and
(2) A nonrefundable $50 processing fee:
(i) You must pay the processing fee to us following the requirements for making payments found in 30 CFR 218.51. You are not required to use Electronic Funds Transfer (EFT) for these payments;
(ii) You must submit the fee with your request under paragraph (c)(1) of this section, and then annually on the date we first determined that you demonstrated financial solvency, as long as you are not able to demonstrate financial solvency under paragraph (a) of this section and you have active appeals.
(d) If you request that we consult a business-information or credit-reporting service or program under paragraph (c) of this section:
(1) We will use criteria similar to that which a potential creditor would use to lend an amount equal to the bond or other surety instrument we would require under subpart B;
(2) For us to consider you financially solvent, the business-information or credit-reporting service or program must demonstrate your degree of risk as low to moderate:
(i) If our bond-approving officer determines that the business-information or credit-reporting service or program information demonstrates your financial solvency to our satisfaction, our bond-approving officer will not require you to post a bond or other surety instrument under subpart B;
(ii) If our bond-approving officer determines that the business-information or credit-reporting service or program information does not demonstrate your financial solvency to our satisfaction, our bond-approving officer will require you to post a bond or other surety instrument under subpart B or pay the obligation.
§ 243.202
When will MMS monitor my financial solvency?
(a) If you are presumptively financially solvent under § 243.201(b), MMS will determine your net worth as described under §§ 243.201(b) and (c) to evaluate your financial solvency at least annually on the date we first determined that you demonstrated financial solvency as long as you have active appeals and each time you appeal a new order.
(b) If you ask us to consult a business-information or credit-reporting service or program under § 243.201(c), we will consult a service or program annually as long as you have active appeals and each time you appeal a new order.
(c) If our bond-approving officer determines that you are no longer financially solvent, you must post a bond or other MMS-specified surety instrument under subpart B.

SUBCHAPTER B—OFFSHORE
Pt. 250

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

Subpart A—General

Authority and Definition of Terms
Sec.
250.101
Authority and applicability.
250.102
What does this part do?
250.103
Where can I find more information about the requirements in this part?
250.104
How may I appeal a decision made under MMS 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
How do I determine well producibility?
250.116
How do I determine producibility if my well is in the Gulf of Mexico?
250.117
How does a determination of well producibility affect royalty status?
250.118
Will MMS approve gas injection?
250.119
Will MMS approve subsurface gas storage?
250.120
How does injecting, storing, or treating gas affect my royalty payments?
250.121
What happens when the reservoir contains both original gas in place and injected gas?
250.122
What effect does subsurface storage have on the lease term?
250.123
Will MMS allow gas storage on unleased lands?
250.124
Will MMS approve gas injection into the cap rock containing a sulphur deposit?

Fees
250.125
Service fees.
250.126
General payment instructions.

Inspection of Operations
250.130
Why does MMS conduct inspections?
250.131
Will MMS notify me before conducting an inspection?
250.132
What must I do when MMS conducts an inspection?
250.133
Will MMS reimburse me for my expenses related to inspections?

Disqualification
250.135
What will MMS do if my operating performance is unacceptable?
250.136
How will MMS 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
How do I designate an operator?
250.144
How do I designate a new operator when a designation of operator terminates?
250.145
How do I designate an agent or a local agent?
250.146
Who is responsible for fulfilling leasehold obligations?

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?

Right-of-Use and Easement
250.160
When will MMS grant me a right-of-use and easement, and what requirements must I meet?
250.161
What else must I submit with my application?
250.162
May I continue my right-of-use and easement after the termination of any lease on which it is situated?
250.163
If I have a State lease, will MMS grant me a right-of-use and easement?
250.164
If I have a State lease, what conditions apply for a right-of-use and easement?
250.165
If I have a State lease, what fees do I have to pay for a right-of-use and easement?
250.166
If I have a State lease, what surety bond must I have for a right-of-use and easement?

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
When may the Secretary cancel my lease and when am I compensated for cancellation?
250.182
When may the Secretary cancel a lease at the exploration stage?
250.183
When may MMS or the Secretary extend or cancel a lease at the development and production stage?
250.184
What is the amount of compensation for lease cancellation?
250.185
When is there no compensation for a lease cancellation?

Information and Reporting Requirements
250.186
What reporting information and report forms must I submit?
250.187
What are MMS' incident reporting requirements?
250.188
What incidents must I report to MMS and when must I report them?
250.189
Reporting requirements for incidents requiring immediate notification.
250.190
Reporting requirements for incidents requiring written notification.
250.191
How does MMS conduct incident investigations?
250.192
What evacuation statistics must I submit?
250.193
Reports and investigations of apparent violations.
250.194
How must I protect archaeological resources?
250.195
What notification does MMS require on the production status of wells?
250.196
Reimbursements for reproduction and processing costs.
250.197
Data and information to be made available to the public or for limited inspection.

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
What criteria must the Exploration Plan (EP), Development and Production Plan (DPP), or Development Operations Coordination Document (DOCD) meet?
250.203
Where can wells be located under an EP, DPP, or DOCD?
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?
250.206
How do I submit the EP, DPP, or DOCD?

Ancillary Activities
250.207
What ancillary activities may I conduct?
250.208
If I conduct ancillary activities, what notices must I provide?
250.209
What is the MMS review process for the notice?
250.210
If I conduct ancillary activities, what reporting and data/information retention requirements must I satisfy?

Contents of Exploration Plans (EP)
250.211
What must the EP include?
250.212
What information must accompany the EP?
250.213
What general information must accompany the EP?
250.214
What geological and geophysical (G&G) information must accompany the EP?
250.215
What hydrogen sulfide (H2S) information must accompany the EP?
250.216
What biological, physical, and socioeconomic information must accompany the EP?
250.217
What solid and liquid wastes and discharges information and cooling water intake information must accompany the EP?
250.218
What air emissions information must accompany the EP?
250.219
What oil and hazardous substance spills information must accompany the EP?
250.220
If I propose activities in the Alaska OCS Region, what planning information must accompany the EP?
250.221
What environmental monitoring information must accompany the EP?
250.222
What lease stipulations information must accompany the EP?
250.223
What mitigation measures information must accompany the EP?
250.224
What information on support vessels, offshore vehicles, and aircraft you will use must accompany the EP?
250.225
What information on the onshore support facilities you will use must accompany the EP?
250.226
What Coastal Zone Management Act (CZMA) information must accompany the EP?
250.227
What environmental impact analysis (EIA) information must accompany the EP?
250.228
What administrative information must accompany the EP?

Review and Decision Process for the EP
250.231
After receiving the EP, what will MMS do?
250.232
What actions will MMS take after the EP is deemed submitted?
250.233
What decisions will MMS make on the EP and within what timeframe?
250.234
How do I submit a modified EP or resubmit a disapproved EP, and when will MMS make a decision?
250.235
If a State objects to the EP's coastal zone consistency certification, what can I do?

Contents of Development and Production Plans (DPP) and Development Operations Coordination Documents (DOCD)
250.241
What must the DPP or DOCD include?
250.242
What information must accompany the DPP or DOCD?
250.243
What general information must accompany the DPP or DOCD?
250.244
What geological and geophysical (G&G) information must accompany the DPP or DOCD?
250.245
What hydrogen sulfide (H2S) information must accompany the DPP or DOCD?
250.246
What mineral resource conservation information must accompany the DPP or DOCD?
250.247
What biological, physical, and socioeconomic information must accompany the DPP or DOCD?
250.248
What solid and liquid wastes and discharges information and cooling water intake information must accompany the DPP or DOCD?
250.249
What air emissions information must accompany the DPP or DOCD?
250.250
What oil and hazardous substance spills information must accompany the DPP or DOCD?
250.251
If I propose activities in the Alaska OCS Region, what planning information must accompany the DPP?
250.252
What environmental monitoring information must accompany the DPP or DOCD?
250.253
What lease stipulations information must accompany the DPP or DOCD?
250.254
What mitigation measures information must accompany the DPP or DOCD?
250.255
What decommissioning information must accompany the DPP or DOCD?
250.256
What related facilities and operations information must accompany the DPP or DOCD?
250.257
What information on the support vessels, offshore vehicles, and aircraft you will use must accompany the DPP or DOCD?
250.258
What information on the onshore support facilities you will use must accompany the DPP or DOCD?
250.259
What sulphur operations information must accompany the DPP or DOCD?
250.260
What Coastal Zone Management Act (CZMA) information must accompany the DPP or DOCD?
250.261
What environmental impact analysis (EIA) information must accompany the DPP or DOCD?
250.262
What administrative information must accompany the DPP or DOCD?

Review and Decision Process for the DPP or DOCD
250.266
After receiving the DPP or DOCD, what will MMS do?
250.267
What actions will MMS take after the DPP or DOCD is deemed submitted?
250.268
How does MMS respond to recommendations?
250.269
How will MMS evaluate the environmental impacts of the DPP or DOCD?
250.270
What decisions will MMS make on the DPP or DOCD and within what timeframe?
250.271
For what reasons will MMS disapprove the DPP or DOCD?
250.272
If a State objects to the DPP's or DOCD's coastal zone consistency certification, what can I do?
250.273
How do I submit a modified DPP or DOCD or resubmit a disapproved DPP or DOCD?

Post-Approval Requirements for the EP, DPP, and DOCD
250.280
How must I conduct activities under the approved EP, DPP, or DOCD?
250.281
What must I do to conduct activities under the approved EP, DPP, or DOCD?
250.282
Do I have to conduct post-approval monitoring?
250.283
When must I revise or supplement the approved EP, DPP, or DOCD?
250.284
How will MMS require revisions to the approved EP, DPP, or DOCD?
250.285
How do I submit revised and supplemental EPs, DPPs, or DOCDs?

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?

Conservation Information Documents (CID)
250.296
When and how must I submit a CID or a revision to a CID?
250.297
What information must a CID contain?
250.298
How long will MMS take to evaluate and make a decision on the CID?
250.299
What operations require approval of the CID?

Subpart C—Pollution Prevention and Control
250.300
Pollution prevention.
250.301
Inspection of facilities.
250.302
Definitions concerning air quality.
250.303
Facilities described in a new or revised Exploration Plan or Development and Production Plan.
250.304
Existing facilities.

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 stack?
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 (AMP) or an End of Operations Report to MMS?
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.
250.507-250.508
[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.

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.
250.607-250.608
[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
Tubing and wellhead equipment.
250.618
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
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 MMS requirements for assessment of 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
Abandonment and out-of-service requirements for DOI pipelines.
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
Bond requirements for pipeline right-of-way holders.
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 Rates
250.1100
Definitions for production rates.
250.1101
General requirements and classification of reservoirs.
250.1102
Oil and gas production rates.
250.1103
Well production testing.
250.1104
Bottomhole pressure survey.
250.1105
Flaring or venting gas and burning liquid hydrocarbons.
250.1106
Downhole commingling.
250.1107
Enhanced oil and gas recovery operations.

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 MMS require unitization?

Subpart N—Outer Continental Shelf (OCS) Civil Penalties
250.1400
How does MMS 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 MMS review for potential civil penalties?
250.1405
When is a case file developed?
250.1406
When will MMS 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?

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 MMS measure training results?
250.1508
What must I do when MMS administers written or oral tests?
250.1509
What must I do when MMS administers or requires hands-on, simulator, or other types of testing?
250.1510
What will MMS 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 MMS 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 MMS 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 MMS approve partial structure removal or toppling in place?

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?

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

Source:
53 FR 10690, Apr. 1, 1988, unless otherwise noted. Redesignated at 63 FR 29479, May 29, 1998.

Editorial Note:
Nomenclature changes to part 250 appear at 71 FR 46399 and 46400, Aug. 14, 2006.

Subpart A—General

Source:
64 FR 72775, Dec. 28, 1999, unless otherwise noted.

Authority and Definition of Terms
§ 250.101
Authority and applicability.
The Secretary of the Interior (Secretary) authorized the Minerals Management Service (MMS) 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, MMS orders, the lease or right-of-way, and other applicable laws, regulations, and amendments; and
(b) Conform to sound conservation practice to preserve, protect, and develop mineral resources of the OCS to:
(1) Make resources available to meet the Nation's energy needs;
(2) Balance orderly energy resource development with protection of the human, marine, and coastal environments;
(3) Ensure the public receives a fair and equitable return on the resources of the OCS;
(4) Preserve and maintain free enterprise competition; and
(5) Minimize or eliminate conflicts between the exploration, development, and production of oil and natural gas and the recovery of other resources.
§ 250.102
What does this part do?
(a) 30 CFR part 250 contains the regulations of the MMS 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 MMS 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 30 CFR 250 subpart or
(1) Applications for permit to drill | D.
(2) Development and Production Plans (DPP) | B.
(3) Downhole commingling | K.
(4) Exploration Plans (EP) | B.
(5) Flaring | K.
(6) Gas measurement | L.
(7) Off-lease geological and geophysical permits | 30 CFR 251.
(8) Oil spill financial responsibility coverage | 30 CFR 253.
(9) Oil and gas production safety systems | H.
| (10) Oil spill response plans | 30 CFR 254.
(11) Oil and gas well-completion operations | E.
(12) Oil and gas well-workover operations | F.
(13) Decommissioning Activities | Q.
(14) Platforms and structures | I.
(15) Pipelines and Pipeline Rights-of-Way | J.
(16) Sulphur operations | P.
(17) Training | O.
(18) Unitization | M.
[64 FR 72775, Dec. 28, 1999, as amended at 67 FR 35405, May 17, 2002; 68 FR 8422, Feb. 20, 2003; 70 FR 51500, Aug. 30, 2005; 72 FR 25198, May 4, 2007]
§ 250.103
Where can I find more information about the requirements in this part?
MMS 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 MMS.
§ 250.104
How may I appeal a decision made under MMS regulations?
To appeal orders or decisions issued under MMS regulations in 30 CFR parts 250 to 282, follow the procedures in 30 CFR part 290.
§ 250.105
Definitions.
Terms used in this part will have the meanings given in the Act and as defined in this section:
Act means the OCS Lands Act, as amended (43 U.S.C. 1331 et seq.).
Affected State means with respect to any program, plan, lease sale, or other activity proposed, conducted, or approved under the provisions of the Act, any State:
(1) The laws of which are declared, under section 4(a)(2) of the Act, to be the law of the United States for the portion of the OCS on which such activity is, or is proposed to be, conducted;
(2) Which is, or is proposed to be, directly connected by transportation facilities to any artificial island or installation or other device permanently or temporarily attached to the seabed;
(3) Which is receiving, or according to the proposed activity, will receive oil for processing, refining, or transshipment that was extracted from the OCS and transported directly to such State by means of vessels or by a combination of means including vessels;
(4) Which is designated by the Secretary as a State in which there is a substantial probability of significant impact on or damage to the coastal, marine, or human environment, or a State in which there will be significant changes in the social, governmental, or economic infrastructure, resulting from the exploration, development, and production of oil and gas anywhere on the OCS; or
(5) In which the Secretary finds that because of such activity there is, or will be, a significant risk of serious damage, due to factors such as prevailing winds and currents to the marine or coastal environment in the event of any oil spill, blowout, or release of oil or gas from vessels, pipelines, or other transshipment facilities.
Air pollutant means any airborne agent or combination of agents for which the Environmental Protection Agency (EPA) has established, under section 109 of the Clean Air Act, national primary or secondary ambient air quality standards.
Analyzed geological information means data collected under a permit or a lease that have been analyzed. Analysis may include, but is not limited to, identification of lithologic and fossil content, core analysis, laboratory analyses of physical and chemical properties, well logs or charts, results from formation fluid tests, and descriptions of hydrocarbon occurrences or hazardous conditions.
Ancillary activities means 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 MMS approval of an application or permit.
Archaeological interest means capable of providing scientific or humanistic understanding of past human behavior, cultural adaptation, and related topics through the application of scientific or scholarly techniques, such as controlled observation, contextual measurement, controlled collection, analysis, interpretation, and explanation.
Archaeological resource means any material remains of human life or activities that are at least 50 years of age and that are of archaeological interest.
Attainment area means, for any air pollutant, an area that is shown by monitored data or that is calculated by air quality modeling (or other methods determined by the Administrator of EPA to be reliable) not to exceed any primary or secondary ambient air quality standards established by EPA.
Best available and safest technology (BAST) means the best available and safest technologies that the Director determines to be economically feasible wherever failure of equipment would have a significant effect on safety, health, or the environment.
Best available control technology (BACT) means an emission limitation based on the maximum degree of reduction for each air pollutant subject to regulation, taking into account energy, environmental and economic impacts, and other costs. The Regional Director will verify the BACT on a case-by-case basis, and it may include reductions achieved through the application of processes, systems, and techniques for the control of each air pollutant.
Coastal environment means the physical, atmospheric, and biological components, conditions, and factors that interactively determine the productivity, state, condition, and quality of the terrestrial ecosystem from the shoreline inward to the boundaries of the coastal zone.
Coastal zone means the coastal waters (including the lands therein and thereunder) and the adjacent shorelands (including the waters therein and thereunder) strongly influenced by each other and in proximity to the shorelands of the several coastal States. The coastal zone includes islands, transition and intertidal areas, salt marshes, wetlands, and beaches. The coastal zone extends seaward to the outer limit of the U.S. territorial sea and extends inland from the shorelines to the extent necessary to control shorelands, the uses of which have a direct and significant impact on the coastal waters, and the inward boundaries of which may be identified by the several coastal States, under the authority in section 305(b)(1) of the Coastal Zone Management Act (CZMA) of 1972.
Competitive reservoir means a reservoir in which there are one or more producible or producing well completions on each of two or more leases or portions of leases, with different lease operating interests, from which the lessees plan future production.
Correlative rights when used with respect to lessees of adjacent leases, means the right of each lessee to be afforded an equal opportunity to explore for, develop, and produce, without waste, minerals from a common source.
Data means facts and statistics, measurements, or samples that have not been analyzed, processed, or interpreted.
Departures means approvals granted by the appropriate MMS representative for operating requirements/procedures other than those specified in the regulations found in this part. These requirements/procedures may be necessary to control a well; properly develop a lease; conserve natural resources, or protect life, property, or the marine, coastal, or human environment.
Development means those activities that take place following discovery of minerals in paying quantities, including but not limited to geophysical activity, drilling, platform construction, and operation of all directly related onshore support facilities, and which are for the purpose of producing the minerals discovered.
Development geological and geophysical (G&G) activities means those G&G and related data-gathering activities on your lease or unit that you conduct following discovery of oil, gas, or sulphur in paying quantities to detect or imply the presence of oil, gas, or sulphur in commercial quantities.
Director means the Director of MMS of the U.S. Department of the Interior, or an official authorized to act on the Director's behalf.
District Manager means the MMS officer with authority and responsibility for operations or other designated program functions for a district within an MMS 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 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 means 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 means pressure maintenance operations, secondary and tertiary recovery, cycling, and similar recovery operations that alter the natural forces in a reservoir to increase the ultimate recovery of oil or gas.
Existing facility, as used in § 250.303, 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 § 250.303, 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.
Gas reservoir means a reservoir that contains hydrocarbons predominantly in a gaseous (single-phase) state.
Gas-well completion means a well completed in a gas reservoir or in the associated gas-cap of an oil reservoir.
Geological and geophysical (G&G) explorations means those G&G surveys on your lease or unit that use seismic reflection, seismic refraction, magnetic, gravity, gas sniffers, coring, or other systems to detect or imply the presence of oil, gas, or sulphur in commercial quantities.
Governor means the Governor of a State, or the person or entity designated by, or under, State law to exercise the powers granted to such Governor under the Act.
H 2 S absent means:
(1) Drilling, logging, coring, testing, or producing operations have confirmed the absence of H2S in concentrations that could potentially result in atmospheric concentrations of 20 ppm or more of H2S; or
(2) Drilling in the surrounding areas and correlation of geological and seismic data with equivalent stratigraphic units have confirmed an absence of H2S throughout the area to be drilled.
H 2 S present means drilling, logging, coring, testing, or producing operations have confirmed the presence of H2S in concentrations and volumes that could potentially result in atmospheric concentrations of 20 ppm or more of H2S.
H 2 S unknown means the designation of a zone or geologic formation where neither the presence nor absence of H2S has been confirmed.
Human environment means the physical, social, and economic components, conditions, and factors that interactively determine the state, condition, and quality of living conditions, employment, and health of those affected, directly or indirectly, by activities occurring on the OCS.
Interpreted geological information means geological knowledge, often in the form of schematic cross sections, 3-dimensional representations, and maps, developed by determining the geological significance of data and analyzed geological information.
Interpreted geophysical information means geophysical knowledge, often in the form of schematic cross sections, 3-dimensional representations, and maps, developed by determining the geological significance of geophysical data and analyzed geophysical information.
Lease means an agreement that is issued under section 8 or maintained under section 6 of the Act and that authorizes exploration for, and development and production of, minerals. The term also means the area covered by that authorization, whichever the context requires.
Lease term pipelines means 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 MMS-approved assignee of the lease, and the owner or the MMS-approved assignee of operating rights for the lease.
Major Federal action means any action or proposal by the Secretary that is subject to the provisions of section 102(2)(C) of the National Environmental Policy Act of 1969, 42 U.S.C. (2)(C) (i.e., an action that will have a significant impact on the quality of the human environment requiring preparation of an environmental impact statement under section 102(2)(C) of the National Environmental Policy Act).
Marine environment means the physical, atmospheric, and biological components, conditions, and factors that interactively determine the productivity, state, condition, and quality of the marine ecosystem. These include the waters of the high seas, the contiguous zone, transitional and intertidal areas, salt marshes, and wetlands within the coastal zone and on the OCS.
Material remains means physical evidence of human habitation, occupation, use, or activity, including the site, location, or context in which such evidence is situated.
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 includes 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 includes, 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 means 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 MMS-approved designated agent of the lessee(s), or the holder of operating rights under an MMS-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 means 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 MMS officer with responsibility and authority for a Region within MMS.
Regional Supervisor means the MMS officer with responsibility and authority for operations or other designated program functions within an MMS Region.
Right-of-use means any authorization issued under this part to use OCS lands.
Right-of-way pipelines are those pipelines that are contained within:
(1) The boundaries of a single lease or unit, but are not owned and operated by a lessee or operator of that lease or unit;
(2) The boundaries of contiguous (not cornering) leases that do not have a common lessee or operator;
(3) The boundaries of contiguous (not cornering) leases that have a common lessee or operator but are not owned and operated by that common lessee or operator; or
(4) An unleased block(s).
Routine operations, for the purposes of subpart F, means 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 high reservoir production rates will decrease ultimate recovery. For submitting the first MER, all oil reservoirs with an associated gas cap are classified as sensitive.
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)).
Waste of oil, gas, or sulphur means:
(1) The physical waste of oil, gas, or sulphur;
(2) The inefficient, excessive, or improper use, or the unnecessary dissipation of reservoir energy;
(3) The locating, spacing, drilling, equipping, operating, or producing of any oil, gas, or sulphur well(s) in a manner that causes or tends to cause a reduction in the quantity of oil, gas, or sulphur ultimately recoverable under prudent and proper operations or that causes or tends to cause unnecessary or excessive surface loss or destruction of oil or gas; or
(4) The inefficient storage of oil.
Welding means all activities connected with welding, including hot tapping and burning.
Wellbay is the area on a facility within the perimeter of the outermost wellheads.
Well-completion operations means 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 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 means 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.
[64 FR 72775, Dec. 28, 1999, as amended at 68 FR 8422, Feb. 20, 2003; 70 FR 41573, July 19, 2005; 70 FR 51500, Aug. 30, 2005; 71 FR 23862, Apr. 25, 2006]

Performance Standards
§ 250.106
What standards will the Director use to regulate lease operations?
The Director will regulate all operations under a lease, right-of-use and easement, or right-of-way to:
(a) Promote orderly exploration, development, and production of mineral resources;
(b) Prevent injury or loss of life;
(c) Prevent damage to or waste of any natural resource, property, or the environment; and
(d) Cooperate and consult with affected States, local governments, other interested parties, and relevant Federal agencies.
§ 250.107
What must I do to protect health, safety, property, and the environment?
(a) You must protect health, safety, property, and the environment by:
(1) Performing all operations in a safe and workmanlike manner; and
(2) Maintaining all equipment and work areas in a safe condition.
(b) You must immediately control, remove, or otherwise correct any hazardous oil and gas accumulation or other health, safety, or fire hazard.
(c) You must use the best available and safest technology (BAST) whenever practical on all exploration, development, and production operations. In general, we consider your compliance with MMS 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.
[64 FR 72775, Dec. 28, 1999, as amended at 73 FR 20171, Apr. 15, 2008]
§ 250.108
What requirements must I follow for cranes and other material-handling equipment?
(a) All cranes installed on fixed platforms must be operated in accordance with American Petroleum Institute's Recommended Practice for Operation and Maintenance of Offshore Cranes (API RP 2D), incorporated by reference as specified in 30 CFR 250.198.
(b) All cranes installed on fixed platforms must be equipped with a functional anti-two block device by March 16, 2005.
(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), incorporated by reference as specified in 30 CFR 250.198.
(d) All cranes manufactured after March 17, 2003, and installed on a fixed platform, must meet the requirements of API Spec 2C, incorporated by reference as specified in 30 CFR 250.198.
(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.
[68 FR 7426, Feb. 14, 2003, as amended at 72 FR 12092, Mar. 15, 2007]
§ 250.109
What documents must I prepare and maintain related to welding?
(a) You must submit a Welding Plan to the District Manager before you begin drilling or production activities on a lease. You may not begin welding until the District Manager has approved your plan.
(b) You must keep the following at the site where welding occurs:
(1) A copy of the plan and its approval letter; and
(2) Drawings showing the designated safe-welding areas.
§ 250.110
What must I include in my welding plan?
You must include all of the following in the Welding Plan that you prepare under § 250.109:
(a) Standards or requirements for welders;
(b) How you will ensure that only qualified personnel weld;
(c) Practices and procedures for safe welding that address:
(1) Welding in designated safe areas;
(2) Welding in undesignated areas, including wellbay;
(3) Fire watches;
(4) Maintenance of welding equipment; and
(5) Plans showing all designated safe-welding areas.
(d) How you will prevent spark-producing activities (i.e., grinding, abrasive blasting/cutting and arc-welding) in hazardous locations.
§ 250.111
Who oversees operations under my welding plan?
A welding supervisor or a designated person in charge must be thoroughly familiar with your welding plan. This person must ensure that each welder is properly qualified according to the welding plan. This person also must inspect all welding equipment before welding.
§ 250.112
What standards must my welding equipment meet?
Your welding equipment must meet the following requirements:
(a) All engine-driven welding equipment must be equipped with spark arrestors and drip pans;
(b) Welding leads must be completely insulated and in good condition;
(c) Hoses must be leak-free and equipped with proper fittings, gauges, and regulators; and
(d) Oxygen and fuel gas bottles must be secured in a safe place.
§ 250.113
What procedures must I follow when welding?
(a) Before you weld, you must move any equipment containing hydrocarbons or other flammable substances at least 35 feet horizontally from the welding area. You must move similar equipment on lower decks at least 35 feet from the point of impact where slag, sparks, or other burning materials could fall. If moving this equipment is impractical, you must protect that equipment with flame-proofed covers, shield it with metal or fire-resistant guards or curtains, or render the flammable substances inert.
(b) While you weld, you must monitor all water-discharge-point sources from hydrocarbon-handling vessels. If a discharge of flammable fluids occurs, you must stop welding.
(c) If you cannot weld in one of the designated safe-welding areas that you listed in your safe welding plan, you must meet the following requirements:
(1) You may not begin welding until:
(i) The welding supervisor or designated person in charge advises in writing that it is safe to weld.
(ii) You and the designated person in charge inspect the work area and areas below it for potential fire and explosion hazards.
(2) During welding, the person in charge must designate one or more persons as a fire watch. The fire watch must:
(i) Have no other duties while actual welding is in progress;
(ii) Have usable firefighting equipment;
(iii) Remain on duty for 30 minutes after welding activities end; and
(iv) Maintain a continuous surveillance with a portable gas detector during the welding and burning operation if welding occurs in an area not equipped with a gas detector.
(3) You may not weld piping, containers, tanks, or other vessels that have contained a flammable substance unless you have rendered the contents inert and the designated person in charge has determined it is safe to weld. This does not apply to approved hot taps.
(4) You may not weld within 10 feet of a wellbay unless you have shut in all producing wells in that wellbay.
(5) You may not weld within 10 feet of a production area, unless you have shut in that production area.
(6) You may not weld while you drill, complete, workover, or conduct wireline operations unless:
(i) The fluids in the well (being drilled, completed, worked over, or having wireline operations conducted) are noncombustible; and
(ii) You have precluded the entry of formation hydrocarbons into the wellbore by either mechanical means or a positive overbalance toward the formation.
§ 250.114
How must I install and operate electrical equipment?
The requirements in this section apply to all electrical equipment on all platforms, artificial islands, fixed structures, and their facilities.
(a) You must classify all areas according to API RP 500, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Division 1 and Division 2, or API RP 505, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Zone 0, Zone 1, and Zone 2.
(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 (incorporated by reference as specified 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 (incorporated by reference as specified 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.
[64 FR 72775, Dec. 28, 1999, as amended at 65 FR 219, Jan. 4, 2000; 68 FR 43298, July 22, 2003]
§ 250.115
How do I determine well producibility?
You must follow the procedures in this section to determine well producibility if your well is not in the GOM. If your well is in the GOM you must follow the procedures in either this section or in § 250.116 of this subpart.
(a) You must write to the Regional Supervisor asking for permission to determine producibility.
(b) You must either:
(1) Allow the District Manager to witness each test that you conduct under this section; or
(2) Receive the District Manager's prior approval so that you can submit either test data with your affidavit or third party test data.
(c) If the well is an oil well, you must conduct a production test that lasts at least 2 hours after flow stabilizes.
(d) If the well is a gas well, you must conduct a deliverability test that lasts at least 2 hours after flow stabilizes, or a four-point back pressure test.
§ 250.116
How do I determine producibility if my well is in the Gulf of Mexico?
If your well is in the GOM, you must follow either the procedures in § 250.115 of this subpart or the procedures in this section to determine producibility.
(a) You must write to the Regional Supervisor asking for permission to determine producibility.
(b) You must provide or make available to the Regional Supervisor, as requested, the following log, core, analyses, and test criteria that MMS will consider collectively:
(1) A log showing sufficient porosity in the producible section.
(2) Sidewall cores and core analyses that show that the section is capable of producing oil or gas.
(3) Wireline formation test and/or mud-logging analyses that show that the section is capable of producing oil or gas.
(4) A resistivity or induction electric log of the well showing a minimum of 15 feet (true vertical thickness except for horizontal wells) of producible sand in one section.
(c) No section that you count as producible under paragraph (b)(4) of this section may include any interval that appears to be water saturated.
(d) Each section you count as producible under paragraph (b)(4) of this section must exhibit:
(1) A minimum true resistivity ratio of the producible section to the nearest clean or water-bearing sand of at least 5:1; and
(2) One of the following:
(i) Electrical spontaneous potential exceeding 20-negative millivolts beyond the shale baseline; or
(ii) Gamma ray log deflection of at least 70 percent of the maximum gamma ray deflection in the nearest clean water-bearing sand—if mud conditions prevent a 20-negative millivolt reading beyond the shale baseline.
§ 250.117
How does a determination of well producibility affect royalty status?
A determination of well producibility invokes minimum royalty status on the lease as provided in 30 CFR 202.53.
§ 250.118
Will MMS 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 MMS approval for injection, you must:
(1) Show that the injection will not result in undue interference with operations under existing leases; and
(2) Submit a written application to the Regional Supervisor for injection of gas.
(b) The Regional Supervisor will approve gas injection applications that:
(1) Enhance recovery;
(2) Prevent flaring of casinghead gas; or
(3) Implement other conservation measures approved by the Regional Supervisor.
§ 250.119
Will MMS approve subsurface gas storage?
The Regional Supervisor may authorize subsurface storage of gas on the OCS, on and off-lease, for later commercial benefit. To receive MMS approval you must:
(a) Show that the subsurface storage of gas will not result in undue interference with operations under existing leases; and
(b) Sign a storage agreement that includes the required payment of a storage fee or rental.
§ 250.120
How does injecting, storing, or treating gas affect my royalty payments?
(a) If you produce gas from an OCS lease and inject it into a reservoir on the lease or unit for the purposes cited in § 250.118(b), you are not required to pay royalties until you remove or sell the gas from the reservoir.
(b) If you produce gas from an OCS lease and store it according to § 250.119, 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.
§ 250.121
What happens when the reservoir contains both original gas in place and injected gas?
If the reservoir contains both original gas in place and injected gas, when you produce gas from the reservoir you must use an MMS-approved formula to determine the amounts of injected or stored gas and gas original to the reservoir.
§ 250.122
What effect does subsurface storage have on the lease term?
If you use a lease area for subsurface storage of gas, it does not affect the continuance or expiration of the lease.
§ 250.123
Will MMS allow gas storage on unleased lands?
You may not store gas on unleased lands unless the Regional Supervisor approves a right-of-use and easement for that purpose, under §§ 250.160 through 250.166 of this subpart.
§ 250.124
Will MMS approve gas injection into the cap rock containing a sulphur deposit?
To receive the Regional Supervisor's approval to inject gas into the cap rock of a salt dome containing a sulphur deposit, you must show that the injection:
(a) Is necessary to recover oil and gas contained in the cap rock; and
(b) Will not significantly increase potential hazards to present or future sulphur mining operations.

Fees
§ 250.125
Service fees.
(a) The table in this paragraph (a) shows the fees that you must pay to MMS for the services listed. The fees will be adjusted periodically according to the Implicit Price Deflator for Gross Domestic Product by publication of a document in the Federal Register. If a significant adjustment is needed to arrive at the new actual cost for any reason other than inflation, then a proposed rule containing the new fees will be published in the Federal Register for comment.
Service Fee Table
Service—processing of the following: | Fee amount | 30 CFR citation
(1) Change in Designation of Operator | $150 | § 250.143(d).
(2) Right-of-Use and Easement for State lessee | $2,350 | § 250.165.
(3) Suspension of Operations/Suspension of Production (SOO/SOP) Request | $1,800 | § 250.171(e).
(4) Exploration Plan (EP) | $3,250 for each surface location; no fee for revisions | § 250.211(d).
(5) Development and Production Plan (DPP) or Development Operations Coordination Document (DOCD) | $3,750 for each well proposed; no fee for revisions | § 250.241(e).
(6) Deepwater Operations Plan | $3,150 | § 250.292(p).
(7) Conservation Information Document | $24,200 | § 250.296(a).
(8) Application for Permit to Drill (APD; Form MMS-123) | $1,850 for initial applications only; no fee for revisions | § 250.410(d); § 250.411; § 250.460; § 250.513(b); § 250.515; § 250.1605; § 250.1617(a); § 250.1622.
(9) Application for Permit to Modify (APM; Form MMS-124) | $110 | § 250.460; § 250.465(b); § 250.513(b); § 250.515; § 250.613(b); § 250.615; § 250.1618(a); § 250.1622; § 250.1704(g).
(10) New Facility Production Safety System Application for facility with more than 125 components | $4,750 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 (incorporated by reference as specified in § 250.198); $12,500 additional fee will be charged if MMS deems it necessary to visit a facility offshore, and $6,500 to visit a facility in a shipyard | § 250.802(e).
| (11) New Facility Production Safety System Application for facility with 25-125 components | $1,150 Additional fee of $7,850 will be charged if MMS deems it necessary to visit a facility offshore, and $4,500 to visit a facility in a shipyard | § 250.802(e).
(12) New Facility Production Safety System Application for facility with fewer than 25 components | $570 | § 250.802(e).
(13) Production Safety System Application—Modification with more than 125 components reviewed | $530 | § 250.802(e).
(14) Production Safety System Application—Modification with 25-125 components reviewed | $190 | § 250.802(e).
(15) Production Safety System Application—Modification with fewer than 25 components reviewed | $80 | § 250.802(e).
(16) Platform Application—Installation—Under the Platform Verification Program | $19,900 | § 250.905(k).
(17) Platform Application—Installation—Fixed Structure Under the Platform Approval Program | $2,850 | § 250.905(k).
(18) Platform Application—Installation—Caisson/Well Protector | $1,450 | § 250.905(k).
(19) Platform Application—Modification/Repair | $3,400 | § 250.905(k).
(20) New Pipeline Application (Lease Term) | $3,100 | § 250.1000(b).
(21) Pipeline Application—Modification (Lease Term) | $1,800 | § 250.1000(b).
(22) Pipeline Application—Modification (ROW) | $3,650 | § 250.1000(b).
(23) Pipeline Repair Notification | $340 | § 250.1008(e).
(24) Pipeline Right-of-Way (ROW) Grant Application | $2,350 | § 250.1015(a).
(25) Pipeline Conversion of Lease Term to ROW | $200 | § 250.1015(a).
(26) Pipeline ROW Assignment | $170 | § 250.1018(b).
(27) 500 Feet From Lease/Unit Line Production Request | $3,300 | § 250.1101(f).
(28) Gas Cap Production Request | $4,200 | § 250.1101(f).
(29) Downhole Commingling Request | $4,900 | § 250.1106(d).
(30) Complex Surface Commingling and Measurement Application | $3,550 | § 250.1202(a); § 250.1203(b); § 250.1204(a).
(31) Simple Surface Commingling and Measurement Application | $1,200 | § 250.1202(a); § 250.1203(b); § 250.1204(a).
(32) Voluntary Unitization Proposal or Unit Expansion | $10,700 | § 250.1303(d).
(33) Unitization Revision | $760 | § 250.1303(d).
(34) Application to Remove a Platform or Other Facility | $4,100 | § 250.1727.
(35) Application to Decommission a Pipeline (Lease Term) | $1,000 | § 250.1751(a) or § 250.1752(a).
(36) Application to Decommission a Pipeline (ROW) | $1,900 | § 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.
[70 FR 49875, Aug. 25, 2005, as amended at 71 FR 40909, July 19, 2006; 72 FR 25199, May 4, 2007]
§ 250.126
General payment instructions.
(a) Payment of fees associated with electronic applications. If you submitted an application through eWell or OCS Connect, you must use the interactive payment feature in that system.
(b) Payment of fees for applications not submitted electronically. For applications not submitted electronically through eWell or OCS Connect, MMS prefers you to use credit card or automated clearing house (ACH) payments through the PAY.GOV Web site.
(1) Payment using PAY.GOV Web site. The PAY.GOV Web site may be accessed through links on the MMS Offshore Web site at: http://www.mms.gov/offshore/ homepage or directly through PAY.GOV at: https://www.pay.gov/paygov/. If paying by credit card or ACH, you must include a copy of the PAY.GOV confirmation receipt page with your application.
(2) MMS will also accept payments by any of the payment means listed in this section. Your payment must be payable to: “Department of the Interior—Minerals Management Service” or “DOI-MMS” and must include your MMS company number. MMS prefers that you use these payment documents in the order presented:
(i) Commercial check drawn on a solvent bank;
(ii) Certified check;
(iii) Cashier's check;
(iv) Money order; or
(v) Bank draft drawn on a solvent bank or a Federal Reserve check.
(c) Terms used in this section have the following meanings:
(1) Automated Clearing House or ACH is a type of electronic fund transfer using the ACH network.
(2) PAY.GOV is a U.S. Treasury payment system used by MMS to receive credit card and ACH payments for processing OCS plans, permits, and other related applications or documents.
[71 FR 40911, July 19, 2006]

Inspection of Operations
§ 250.130
Why does MMS conduct inspections?
MMS 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 approved Exploration Plan or Development and Production Plans; or right-of-use and easement, and other applicable laws and regulations; and
(b) To determine whether equipment designed to prevent or ameliorate blowouts, fires, spillages, or other major accidents has been installed and is operating properly according to the requirements of this part.
§ 250.131
Will MMS notify me before conducting an inspection?
MMS conducts both scheduled and unscheduled inspections.
§ 250.132
What must I do when MMS conducts an inspection?
(a) When MMS 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.
§ 250.133
Will MMS reimburse me for my expenses related to inspections?
Upon request, MMS will reimburse you for food, quarters, and transportation that you provide for MMS representatives while they inspect lease facilities and operations. You must send us your reimbursement request within 90 days of the inspection.

Disqualification
§ 250.135
What will MMS do if my operating performance is unacceptable?
If your operating performance is unacceptable, MMS 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 MMS officials before imposing a disqualification.
§ 250.136
How will MMS determine if my operating performance is unacceptable?
In determining if your operating performance is unacceptable, MMS will consider, individually or collectively:
(a) Accidents and their nature;
(b) Pollution events, environmental damages and their nature;
(c) Incidents of noncompliance;
(d) Civil penalties;
(e) Failure to adhere to OCS lease obligations; or
(f) Any other relevant factors.

Special Types of Approvals
§ 250.140
When will I receive an oral approval?
When you apply for MMS approval of any activity, we normally give you a written decision. The following table shows circumstances under which we may give an oral approval.
When you | We may | And
(a) Request approval orally | Give you an oral approval | You must then confirm the oral request by sending us a written request within 72 hours.
(b) Request approval in writing | Give you an oral approval if quick action is needed | We will send you a written approval afterward. It will include any conditions that we place on the oral approval.
(c) Request approval orally for gas flaring | Give you an oral approval | You don't have to follow up with a written request unless the Regional Supervisor requires it. When you stop the approved flaring, you must promptly send a letter summarizing the location, dates and hours, and volumes of liquid hydrocarbons produced and gas flared by the approved flaring. (See 30 CFR 250, subpart K.)
§ 250.141
May I ever use alternate procedures or equipment?
You may use alternate procedures or equipment after receiving approval as described in this section.
(a) Any alternate procedures or equipment that you propose to use must provide a level of safety and environmental protection that equals or surpasses current MMS 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 Supervisor. Your presentation must describe the site-specific application(s), performance characteristics, and safety features of the proposed procedure or equipment.
§ 250.142
How do I receive approval for departures?
We may approve departures to the operating requirements. You may apply for a departure by writing to the District Manager or Regional Supervisor.
[65 FR 6536, Feb. 10, 2000]
§ 250.143
How do I designate an operator?
(a) You must provide the Regional Supervisor an executed Designation of Operator form (Form MMS-1123) unless you are the only lessee and are the only person conducting lease operations. When there is more than one lessee, each lessee must submit the Designation of Operator form and the Regional Supervisor must approve the designation before the designated operator may begin operations on the leasehold.
(b) This designation is authority for the designated operator to act on your behalf and to fulfill your obligations under the Act, the lease, and the regulations in this part.
(c) You, or your designated operator, must immediately provide the Regional Supervisor a written notification of any change of address.
(d) If you change the designated operator on your lease, you must pay the service fee listed in § 250.125 of this subpart with your request for a change in designation of operator. Should there be multiple lessees, all designation of operator forms must be collected by one lessee and submitted to MMS in a single submittal, which is subject to only one filing fee.
[64 FR 72775, Dec. 28, 1999, as amended at 70 FR 49876, Aug. 25, 2005; 72 FR 25200, May 4, 2007]
§ 250.144
How do I designate a new operator when a designation of operator terminates?
(a) When a Designation of Operator terminates, the Regional Supervisor must approve a new designated operator before you may continue operations. Each lessee must submit a new executed Designation of Operator form.
(b) If your Designation of Operator is terminated, or a controversy develops between you and your designated operator, you and your designated operator must protect the lessor's interests.
§ 250.145
How do I designate an agent or a local agent?
(a) You or your designated operator may designate for the Regional Supervisor's approval, or the Regional Director may require you to designate an agent empowered to fulfill your obligations under the Act, the lease, or the regulations in this part.
(b) You or your designated operator may designate for the Regional Supervisor's approval a local agent empowered to receive notices and submit requests, applications, notices, or supplemental information.
§ 250.146
Who is responsible for fulfilling leasehold obligations?
(a) When you are not the sole lessee, you and your co-lessee(s) are jointly and severally responsible for fulfilling your obligations under the provisions of 30 CFR parts 250 through 282, 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, 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 require the lessee to meet a requirement or perform an action, the lessee, operator (if one has been designated), and the person actually performing the activity to which the requirement applies are jointly and severally responsible for complying with the regulation.

Naming and Identifying Facilities and Wells (Does Not Include MODUs)
§ 250.150
How do I name facilities and wells in the Gulf of Mexico Region?
(a) Assign each facility a letter designation except for those types of facilities identified in paragraph (c)(1) of this section. For example, A, B, CA, or CB.
(1) After a facility is installed, rename each predrilled well that was assigned only a number and was suspended temporarily at the mudline or at the surface. Use a letter and number designation. The letter used must be the same as that of the production facility, and the number used must correspond to the order in which the well was completed, not necessarily the number assigned when it was drilled. For example, the first well completed for production on Facility A would be renamed Well A-1, the second would be Well A-2, and so on; and
(2) When you have more than one facility on a block, each facility installed, and not bridge-connected to another facility, must be named using a different letter in sequential order. For example, EC 222A, EC 222B, EC 222C.
(3) When you have more than one facility on multiple blocks in a local area being co-developed, each facility installed and not connected with a walkway to another facility should be named using a different letter in sequential order with the block number corresponding to the block on which the platform is located. For example, EC 221A, EC 222B and EC 223C.
(b) In naming multiple well caissons, you must assign a letter designation.
(c) In naming single well caissons, you must use certain criteria as follows:
(1) For single well caissons not attached to a facility with a walkway, use the well designation. For example, Well No. 1;
(2) For single well caissons attached to a facility with a walkway, use the same designation as the facility. For example, rename Well No.10 as A-10; and
(3) For single well caissons with production equipment, use a letter designation for the facility name and a letter plus number designation for the well. For example, the Well No. 1 caisson would be designated as Facility A, and the well would be Well A-1.
§ 250.151
How do I name facilities in the Pacific Region?
The operator assigns a name to the facility.
§ 250.152
How do I name facilities in the Alaska Region?
Facilities will be named and identified according to the Regional Director's directions.
§ 250.153
Do I have to rename an existing facility or well?
You do not have to rename facilities installed and wells drilled before January 27, 2000, unless the Regional Director requires it.
§ 250.154
What identification signs must I display?
(a) You must identify all facilities, artificial islands, and mobile offshore drilling units with a sign maintained in a legible condition.
(1) You must display an identification sign that can be viewed from the waterline on at least one side of the platform. The sign must use at least 3-inch letters and figures.
(2) When helicopter landing facilities are present, you must display an additional identification sign that is visible from the air. The sign must use at least 12-inch letters and figures and must also display the weight capacity of the helipad unless noted on the top of the helipad. If this sign is visible to both helicopter and boat traffic, then the sign in paragraph (a)(1) of this section is not required.
(3) Your identification sign must:
(i) List the name of the lessee or designated operator;
(ii) In the GOM OCS Region, list the area designation or abbreviation and the block number of the facility location as depicted on OCS Official Protraction Diagrams or leasing maps;
(iii) In the Pacific OCS Region, list the lease number on which the facility is located; and
(iv) List the name of the platform, structure, artificial island, or mobile offshore drilling unit.
(b) You must identify singly completed wells and multiple completions as follows:
(1) For each singly completed well, list the lease number and well number on the wellhead or on a sign affixed to the wellhead;
(2) For wells with multiple completions, downhole splitter wells, and multilateral wells, identify each completion in addition to the well name and lease number individually on the well flowline at the wellhead; and
(3) For subsea wells that flow individually into separate pipelines, affix the required sign on the pipeline or surface flowline dedicated to that subsea well at a convenient location on the receiving platform. For multiple subsea wells that flow into a common pipeline or pipelines, no sign is required.

Right-of-use and Easement
§ 250.160
When will MMS grant me a right-of-use and easement, and what requirements must I meet?
MMS may grant you a right-of-use and easement on leased and unleased lands on the OCS, if you meet these requirements:
(a) You must need the right-of-use and easement to construct and maintain platforms, artificial islands, and installations and other devices at an OCS site other than an OCS lease you own, that are:
(1) Permanently or temporarily attached to the seabed; and
(2) Used for conducting exploration, development, and production activities or other operations on or off lease; or
(3) Used for other purposes approved by MMS.
(b) You must exercise the right-of-use and easement according to the regulations of this part;
(c) You must meet the requirements at 30 CFR 256.35 (Qualification of lessees); establish a regional Company File as required by MMS; and must meet bonding requirements;
(d) If you apply for a right-of-use and easement on a leased area, you must notify the lessee and give her/him an opportunity to comment on your application; and
(e) You must receive MMS approval for all platforms, artificial islands, and installations and other devices permanently or temporarily attached to the seabed.
(f) You must pay a rental amount as required by paragraph (g) of this section if:
(1) You obtain a right-of-use and easement after January 12, 2004; or
(2) You ask MMS to modify your right-of-use and easement to change the footprint of the associated platform, artificial island, or installation or device.
(g) If you meet either of the conditions in paragraph (f) of this section, you must pay a rental amount to MMS as shown in the following table:
If... | Then...
(1) Your right-of-use and easement site is located in water depths of less than 200 meters; | You must pay a rental of $5 per acre per year with a minimum of $450 per year. The area subject to annual rental includes the areal extent of anchor chains, pipeline risers, and other equipment associated with the platform, artificial island, installation or device.
(2) Your right-of-use and easement site is located in water depths of 200 meters or greater; | You must pay a rental of $7.50 per acre per year with a minimum of $675 per year. The area subject to annual rental includes the areal extent of anchor chains, pipeline risers, and other equipment associated with the platform, artificial island, or installation or device.
(h) You may make the rental payments required by paragraph (g)(1) and (g)(2) of this section on an annual basis, for a 5-year period, or for multiples of 5 years. You must make the first payment at the time you submit the right-of-use and easement application. You must make all subsequent payments before the respective time periods begin.
(i) Late payments. An interest charge will be assessed on unpaid and underpaid amounts from the date the amounts are due, in accordance with the provisions found in 30 CFR 218.54. If you fail to make a payment that is late after written notice from MMS, MMS may initiate cancellation of the right-of-use grant and easement.
[64 FR 72775, Dec. 28, 1999, as amended at 68 FR 69311, Dec. 12, 2003; 69 FR 29433, May 24, 2004; 72 FR 25200, May 4, 2007]
§ 250.161
What else must I submit with my application?
With your application, you must describe the proposed use giving:
(a) Details of the proposed uses and activities including access needs and special rights of use that you may need;
(b) A description of all facilities for which you are seeking authorization;
(c) A map or plat describing primary and alternate project locations; and
(d) A schedule for constructing any new facilities, drilling or completing any wells, anticipated production rates, and productive life of existing production facilities.
§ 250.162
May I continue my right-of-use and easement after the termination of any lease on which it is situated?
If your right-of-use and easement is on a lease, you may continue to exercise the right-of-use and easement after the lease on which it is situated terminates. You must only use the right-of-use and easement for the purpose that the grant specifies. All future lessees of that portion of the OCS on which your right-of-use and easement is situated must continue to recognize the right-of-use and easement for the purpose that the grant specifies.
§ 250.163
If I have a State lease, will MMS grant me a right-of-use and easement?
(a) MMS may grant a lessee of a State lease located adjacent to or accessible from the OCS a right-of-use and easement on the OCS.
(b) MMS will only grant a right-of-use and easement under this paragraph to enable a State lessee to conduct and maintain a device that is permanently or temporarily attached to the seabed (i.e., a platform, artificial island, or installation). The lessee must use the device to explore for, develop, and produce oil and gas from the adjacent or accessible State lease and for other operations related to these activities.
§ 250.164
If I have a State lease, what conditions apply for a right-of-use and easement?
(a) A right-of-use and easement granted under the heading of “Right-of-use and easement” in this subpart is subject to MMS regulations, 30 CFR parts 250 through 282, and any terms and conditions that the Regional Director prescribes.
(b) For the whole or fraction of the first calendar year, and annually after that, you must pay to MMS, in advance, an annual rental payment.
§ 250.165
If I have a State lease, what fees do I have to pay for a right-of-use and easement?
When you apply for a right-of-use and easement, you must pay:
(a) A nonrefundable filing fee as specified in § 250.125; and
(b) The first year's rental as specified in § 250.160(g).
[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998, as amended at 72 FR 25200, May 4, 2007]
§ 250.166
If I have a State lease, what surety bond must I have for a right-of-use and easement?
(a) Before MMS issues you a right-of-use and easement on the OCS, you must furnish the Regional Director a surety bond for $500,000.
(b) The Regional Director may require additional security from you (i.e., security above the prescribed $500,000) to cover additional costs and liabilities for regulatory compliance. This additional surety:
(1) Must be in the form of a supplemental bond or bonds meeting the requirements of 30 CFR 256.54 (General requirements for bonds) or an increase in the coverage of an existing surety bond.
(2) Covers additional costs and liabilities for regulatory compliance, including well abandonment, platform and structure removal, and site clearance from the seafloor of the right-of-use and easement.

Suspensions
§ 250.168
May operations or production be suspended?
(a) You may request approval of a suspension, or the Regional Supervisor may direct a suspension (Directed Suspension), for all or any part of a lease or unit area.
(b) Depending on the nature of the suspended activity, suspensions are labeled either Suspensions of Operations (SOO) or Suspensions of Production (SOP).
§ 250.169
What effect does suspension have on my lease?
(a) A suspension may extend the term of a lease (see § 250.180(b), (d), and (e)). The extension is equal to the length of time the suspension is in effect, except as provided in paragraph (b) of this section.
(b) A Directed Suspension does not extend the term of a lease when the Regional Supervisor directs a suspension because of:
(1) Gross negligence; or
(2) A willful violation of a provision of the lease or governing statutes and regulations.
[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998, as amended at 72 FR 25200, May 4, 2007]
§ 250.170
How long does a suspension last?
(a) MMS 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. MMS 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) MMS may terminate any suspension when the Regional Supervisor determines the circumstances that justified the suspension no longer exist or that other lease conditions warrant termination. The Regional Supervisor will notify you of the reasons for termination and the effective date.
§ 250.171
How do I request a suspension?
You must submit your request for a suspension to the Regional Supervisor, and MMS 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 §§ 250.115, 250.116, or 250.1603 (SOP only);
(d) A commitment to production (SOP only); and
(e) The service fee listed in § 250.125 of this subpart.
[70 FR 49876, Aug. 25, 2005]
§ 250.172
When may the Regional Supervisor grant or direct an SOO or SOP?
The Regional Supervisor may grant or direct an SOO or SOP under any of the following circumstances:
(a) When necessary to comply with judicial decrees prohibiting any activities or the permitting of those activities. The effective date of the suspension will be the effective date required by the action of the court;
(b) When activities pose a threat of serious, irreparable, or immediate harm or damage. This would include a threat to life (including fish and other aquatic life), property, any mineral deposit, or the marine, coastal, or human environment. MMS may require you to do a site-specific study. (See § 250.177(a).)
(c) When necessary for the installation of safety or environmental protection equipment;
(d) When necessary to carry out the requirements of NEPA or to conduct an environmental analysis; or
(e) When necessary to allow for inordinate delays encountered in obtaining required permits or consents, including administrative or judicial challenges or appeals.
§ 250.173
When may the Regional Supervisor direct an SOO or SOP?
The Regional Supervisor may direct a suspension when:
(a) You failed to comply with an applicable law, regulation, order, or provision of a lease or permit; or
(b) The suspension is in the interest of national security or defense.
§ 250.174
When may the Regional Supervisor grant or direct an SOP?
The Regional Supervisor may grant or direct an SOP when the suspension is in the national interest, and it is necessary because the suspension will meet one of the following criteria:
(a) It will allow you to properly develop a lease, including time to construct and install production facilities;
(b) It will allow you time to obtain adequate transportation facilities;
(c) It will allow you time to enter a sales contract for oil, gas, or sulphur. You must show that you are making an effort to enter into the contract(s); or
(d) It will avoid continued operations that would result in premature abandonment of a producing well(s).
§ 250.175
When may the Regional Supervisor grant an SOO?
(a) The Regional Supervisor may grant an SOO when necessary to allow you time to begin drilling or other operations when you are prevented by reasons beyond your control, such as unexpected weather, unavoidable accidents, or drilling rig delays.
(b) The Regional Supervisor may grant an SOO when all of the following conditions are met:
(1) The lease was issued with a primary lease term of 5 years, or with a primary term of 8 years with a requirement to drill within 5 years;
(2) Before the end of the third year of the primary term, you or your predecessor in interest must have acquired and interpreted geophysical information that indicates:
(i) The presence of a salt sheet;
(ii) That all or a portion of a potential hydrocarbon-bearing formation may lie beneath or adjacent to the salt sheet; and
(iii) The salt sheet interferes with identification of the potential hydrocarbon-bearing formation.
(3) The interpreted geophysical information required under paragraph (b)(2) of this section must include full 3-D depth migration beneath the salt sheet and over the entire lease area.
(4) Before requesting the suspension, you have conducted or are conducting additional data processing or interpretation of the geophysical information with the objective of identifying a potential 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) 5 years; or
(ii) 8 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 information that would affect the decision to drill the same geologic structure or stratigraphic trap, as determined by the Regional Supervisor, identified in paragraphs (c)(2) and (c)(3) of this section; or
(iii) Drill a well below 25,000 feet TVD SS into the geologic structure or stratigraphic trap identified as a result of the activities conducted in paragraphs (c)(2), (c)(3), and (c)(4)(i) and (ii) of this section.
[64 FR 72775, Dec. 28, 1999, as amended at 67 FR 44360, July 2, 2002; 70 FR 74663, Dec. 16, 2005; 72 FR 25200, May 4, 2007]
§ 250.176
Does a suspension affect my royalty payment?
A directed suspension may affect the payment of rental or royalties for the lease as provided in § 218.154.
§ 250.177
What additional requirements may the Regional Supervisor order for a suspension?
If MMS 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) MMS 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 250, subpart B.

Primary Lease Requirements, Lease Term Extensions, and Lease Cancellations
§ 250.180
What am I required to do to keep my lease term in effect?
(a) If your lease is in its primary term:
(1) You must submit a report to the District Manager according to paragraphs (h) and (i) of this section whenever production begins initially, whenever production ceases during the last 180 days of the primary term, and whenever production resumes during the last 180 days of the primary term.
(2) Your lease expires at the end of its primary term unless you are conducting operations on your lease (see 30 CFR part 256). For purposes of this section, the term operations means, drilling, well-reworking, or production in paying quantities. The objective of the drilling or well-reworking must be to establish production in paying quantities on the lease.
(b) If you stop conducting operations during the last 180 days of your primary lease term, your lease will expire unless you either resume operations or receive an SOO or an SOP from the Regional Supervisor under §§ 250.172, 250.173, 250.174, or 250.175 before the end of the 180th day after you stop operations.
(c) If you extend your lease term under paragraph (b) of this section, you must pay rental or minimum royalty, as appropriate, for each year or part of the year during which your lease continues in force beyond the end of the primary lease term.
(d) If you stop conducting operations on a lease that has continued beyond its primary term, your lease will expire unless you resume operations or receive an SOO or an SOP from the Regional Supervisor under § 250.172, 250.173, 250.174, or 250.175 before the end of the 180th day after you stop operations.
(e) You may ask the Regional Supervisor to allow you more than 180 days to resume operations on a lease continued beyond its primary term when operating conditions warrant. The request must be in writing and explain the operating conditions that warrant a longer period. In allowing additional time, the Regional Supervisor must determine that the longer period is in the national interest, and it conserves resources, prevents waste, or protects correlative rights.
(f) When you begin conducting operations on a lease that has continued beyond its primary term, you must immediately notify the District Manager either orally or by fax or e-mail and follow up with a written report according to paragraph (g) of this section.
(g) If your lease is continued beyond its primary term, you must submit a report to the District Manager under paragraphs (h) and (i) of this section whenever production begins initially, whenever production ceases, whenever production resumes before the end of the 180-day period after having ceased, or whenever drilling or well-reworking operations begin before the end of the 180-day period.
(h) The reports required by paragraphs (a) and (g) of this section must contain:
(1) Name of lessee or operator;
(2) The well number, lease number, area, and block;
(3) As appropriate, the unit agreement name and number; and
(4) A description of the operation and pertinent dates.
(i) You must submit the reports required by paragraphs (a) and (g) of this section within the following timeframes:
(1) Initialization of production—within 5 days of initial production.
(2) Cessation of production—within 15 days after the first full month of zero production.
(3) Resumption of production—within 5 days of resuming production after ceasing production under paragraph (i)(2) of this section.
(4) Drilling or well reworking operations—within 5 days of beginning and completing the leaseholding operations.
(j) For leases continued beyond the primary term, you must immediately report to the District Manager if operations do not begin before the end of the 180-day period.
§ 250.181
When may the Secretary cancel my lease and when am I compensated for cancellation?
If the Secretary cancels your lease under this part or under 30 CFR part 256, you are entitled to compensation under § 250.184. Section 250.185 states conditions under which you will receive no compensation. The Secretary may cancel a lease after notice and opportunity for a hearing when:
(a) Continued activity on the lease would probably cause harm or damage to life (including fish and other aquatic life), property, any mineral deposits (in areas leased or not leased), or the marine, coastal, or human environment;
(b) The threat of harm or damage will not disappear or decrease to an acceptable extent within a reasonable period of time;
(c) The advantages of cancellation outweigh the advantages of continuing the lease in force; and
(d) A suspension has been in effect for at least 5 years or you request termination of the suspension and lease cancellation.
§ 250.182
When may the Secretary cancel a lease at the exploration stage?
MMS may not approve an exploration plan (EP) under 30 CFR part 250, subpart B, if the Regional Supervisor determines that the proposed activities may cause serious harm or damage to life (including fish and other aquatic life), property, any mineral deposits, the national security or defense, or to the marine, coastal, or human environment, and that the proposed activity cannot be modified to avoid the condition(s). The Secretary may cancel the lease if:
(a) The primary lease term has not expired (or if the lease term has been extended) and exploration has been prohibited for 5 years following the disapproval; or
(b) You request cancellation at an earlier time.
§ 250.183
When may MMS or the Secretary extend or cancel a lease at the development and production stage?
(a) MMS may extend your lease if you submit a DPP and the Regional Supervisor disapproves the plan according to the regulations in 30 CFR part 250, subpart B. Following the disapproval:
(1) MMS will allow you to hold the lease for 5 years, or less time at your request;
(2) Any time within 5 years after the disapproval, you may reapply for approval of the same or a modified plan; and
(3) The Regional Supervisor will approve, disapprove, or require modification of the plan under 30 CFR part 250, subpart B.
(b) If the Regional Supervisor has not approved a DPP or required you to submit a DPP for approval or modification, the Secretary will cancel the lease:
(1) When the 5-year period in paragraph (a)(1) of this section expires; or
(2) If you request cancellation at an earlier time.
§ 250.184
What is the amount of compensation for lease cancellation?
When the Secretary cancels a lease under §§ 250.181, 250.182 or 250.183 of this subpart, you are entitled to receive compensation under 43 U.S.C. 1334 (a)(2)(C). You must show the Director that the amount of compensation claimed is the lesser of paragraph (a) or (b) of this section:
(a) The fair value of the cancelled rights as of the date of cancellation, taking into account both:
(1) Anticipated revenues from the lease; and
(2) Costs reasonably anticipated on the lease, including:
(i) Costs of compliance with all applicable regulations and operating orders; and
(ii) Liability for cleanup costs or damages, or both, in the case of an oil spill.
(b) The excess, if any, over your revenues from the lease (plus interest thereon from the date of receipt to date of reimbursement) of:
(1) All consideration paid for the lease (plus interest from the date of payment to the date of reimbursement); and
(2) All your direct expenditures (plus interest from the date of payment to the date of reimbursement):
(i) After the issue date of the lease; and
(ii) For exploration or development, or both.
(c) Compensation for leases issued before September 18, 1978, will be equal to the amount specified in paragraph (a) of this section.
§ 250.185
When is there no compensation for a lease cancellation?
You will not receive compensation from MMS for lease cancellation if:
(a) MMS disapproves a DPP because you do not receive concurrence by the State under section 307(c)(3)(B) (i) or (ii) of the CZMA, and the Secretary of Commerce does not make the finding authorized by section 307(c)(3)(B)(iii) of the CZMA;
(b) You do not submit a DPP under 30 CFR part 250, subpart B or do not comply with the approved DPP;
(c) As the lessee of a nonproducing lease, you fail to comply with the Act, the lease, or the regulations issued under the Act, and the default continues for 30 days after MMS mails you a notice by overnight mail;
(d) The Regional Supervisor disapproves a DPP because you fail to comply with the requirements of applicable Federal law; or
(e) The Secretary forfeits and cancels a producing lease under section 5(d) of the Act (43 U.S.C. 1334(d)).

Information and Reporting Requirements
§ 250.186
What reporting information and report forms must I submit?
(a) You must submit information and reports as MMS 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 MMS's forms. You must arrange the data on your form identical to the MMS form. If you generate your own form and it omits terms and conditions contained on the official MMS 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 MMS 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 or otherwise exempt from public disclosure under law or regulation.
[64 FR 72775, Dec. 28, 1999. Redesignated at 71 FR 19644, Apr. 17, 2006, as amended at 72 FR 25200, May 4, 2007]
§ 250.187
What are MMS' 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 MMS, 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.
[71 FR 19644, Apr. 17, 2006]
§ 250.188
What incidents must I report to MMS and when must I report them?
(a) You must report the following incidents to the District Manager immediately via oral communication, and provide a written follow-up report (hard copy or electronically transmitted) within 15 calendar days after the incident:
(1) All fatalities.
(2) All injuries that require the evacuation of the injured person(s) from the facility to shore or to another offshore facility.
(3) All losses of well control. “Loss of well control” means:
(i) Uncontrolled flow of formation or other fluids. The flow may be to an exposed formation (an underground blowout) or at the surface (a surface blowout);
(ii) Flow through a diverter; or
(iii) Uncontrolled flow resulting from a failure of surface equipment or procedures.
(4) All fires and explosions.
(5) All reportable releases of hydrogen sulfide (H2S) gas, as defined in § 250.490(l).
(6) All collisions that result in property or equipment damage greater than $25,000. “Collision” means the act of a moving vessel (including an aircraft) striking another vessel, or striking a stationary vessel or object (e.g., a boat striking a drilling rig or platform). “Property or equipment damage” means the cost of labor and material to restore all affected items to their condition before the damage, including, but not limited to, the OCS facility, a vessel, helicopter, or equipment. It does not include the cost of salvage, cleaning, gas-freeing, dry docking, or demurrage.
(7) All incidents involving structural damage to an OCS facility. “Structural damage” means damage severe enough so that operations on the facility cannot continue until repairs are made.
(8) All incidents involving crane or personnel/material handling operations.
(9) All incidents that damage or disable safety systems or equipment (including firefighting systems).
(b) You must provide a written report of the following incidents to the District Manager within 15 calendar days after the incident:
(1) Any injuries that result in one or more days away from work or one or more days on restricted work or job transfer. One or more days means the injured person was not able to return to work or to all of their normal duties the day after the injury occurred;
(2) All gas releases that initiate equipment or process shutdown;
(3) All incidents that require operations personnel on the facility to muster for evacuation for reasons not related to weather or drills;
(4) All other incidents, not listed in paragraph (a) of this section, resulting in property or equipment damage greater than $25,000.
[71 FR 19644, Apr. 17, 2006]
§ 250.189
Reporting requirements for incidents requiring immediate notification.
For an incident requiring immediate notification under § 250.188(a), you must notify the District Manager via oral communication immediately after aiding the injured and stabilizing the situation. Your oral communication must provide the following information:
(a) Date and time of occurrence;
(b) Operator, and operator representative's, name and telephone number;
(c) Contractor, and contractor representative's name and telephone number (if a contractor is involved in the incident or injury/fatality);
(d) Lease number, OCS area, and block;
(e) Platform/facility name and number, or pipeline segment number;
(f) Type of incident or injury/fatality;
(g) Operation or activity at time of incident (i.e., drilling, production, workover, completion, pipeline, crane, etc.); and
(h) Description of the incident, damage, or injury/fatality.
[71 FR 19644, Apr. 17, 2006]
§ 250.190
Reporting requirements for incidents requiring written notification.
(a) For any incident covered under § 250.188, you must submit a written report within 15 calendar days after the incident to the District Manager. The report must contain the following information:
(1) Date and time of occurrence;
(2) Operator, and operator representative's name and telephone number;
(3) Contractor, and contractor representative's name and telephone number (if a contractor is involved in the incident or injury);
(4) Lease number, OCS area, and block;
(5) Platform/facility name and number, or pipeline segment number;
(6) Type of incident or injury;
(7) Operation or activity at time of incident (i.e., drilling, production, workover, completion, pipeline, crane etc.);
(8) Description of incident, damage, or injury (including days away from work, restricted work or job transfer), and any corrective action taken; and
(9) Property or equipment damage estimate (in U.S. dollars).
(b) You may submit a report or form prepared for another agency in lieu of the written report required by paragraph (a) of this section, provided the report or form contains all required information.
(c) The District Manager may require you to submit additional information about an incident on a case-by-case basis.
[71 FR 19644, Apr. 17, 2006]
§ 250.191
How does MMS conduct incident investigations?
Any investigation that MMS 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 MMS. 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 panel meeting. A subpoena may not require a person to attend a panel meeting held at a location more than 100 miles from where a subpoena is served.
(d) Any person giving testimony may request compensation for mileage, and fees for services, within 90 days after the panel meeting. The compensated expenses must be similar to mileage and fees the U.S. District Courts allow.
[71 FR 19645, Apr. 17, 2006]
§ 250.192
What evacuation statistics must I submit?
You must submit evacuation statistics to the Regional Supervisor for a natural occurrence such as an earthquake or hurricane. MMS will notify local and national authorities and the public, as appropriate. Statistics include facilities and rigs evacuated and amount of production shut-in for gas and oil. You must:
(a) Submit the statistics by fax or e-mail as soon as possible when evacuation occurs;
(b) Submit statistics on a daily basis by 11:00 a.m., as conditions allow, during the period of shut-in and evacuation;
(c) Inform MMS when you resume production; and
(d) Submit statistics either by MMS district or the total figures for your operations in the Region.
§ 250.193
Reports and investigations of apparent violations.
Any person may report to MMS 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 MMS receives a report of an apparent violation, or when an MMS employee detects an apparent violation after making an initial determination of the validity, MMS will investigate according to MMS procedures.
§ 250.194
How must I protect archaeological resources?
(a) If the Regional Director has reason to believe that an archaeological resource may exist in the lease area, the Regional Director will require in writing that your EP, DOCD, or DPP be accompanied by an archaeological report. If the archaeological report suggests that an archaeological resource may be present, you must either:
(1) Locate the site of any operation so as not to adversely affect the area where the archaeological resource may be; or
(2) Establish to the satisfaction of the Regional Director that an archaeological resource does not exist or will not be adversely affected by operations. This requires further archaeological investigation, conducted by an archaeologist and a geophysicist, using survey equipment and techniques the Regional Director considers appropriate. You must submit the investigation report to the Regional Director for review.
(b) If the Regional Director determines that an archaeological resource is likely to be present in the lease area and may be adversely affected by operations, the Regional Director will notify you immediately. You must not take any action that may adversely affect the archaeological resource until the Regional Director has told you how to protect the resource.
(c) If you discover any archaeological resource while conducting operations in the lease or right-of-way area, you must immediately halt operations within the area of the discovery and report the discovery to the Regional Director. If investigations determine that the resource is significant, the Regional Director will tell you how to protect it.
[64 FR 72775, Dec. 28, 1999, as amended at 71 FR 23862, Apr. 25, 2006; 72 FR 25200, May 4, 2007]
§ 250.195
What notification does MMS require on the production status of wells?
You must notify the appropriate MMS 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.
[71 FR 23862, Apr. 25, 2006]
§ 250.196
Reimbursements for reproduction and processing costs.
(a) MMS will reimburse you for costs of reproducing data and information that the Regional Director requests if:
(1) You deliver geophysical and geological (G&G) data and information to MMS for the Regional Director to inspect or select and retain;
(2) MMS receives your request for reimbursement and the Regional Director determines that the requested reimbursement is proper; and
(3) The cost is at your lowest rate or at the lowest commercial rate established in the area, whichever is less.
(b) MMS will reimburse you for the costs of processing geophysical information (that does not include cost of data acquisition):
(1) If, at the request of the Regional Director, you processed the geophysical data or information in a form or manner other than that used in the normal conduct of business; or
(2) If you collected the information under a permit that MMS issued to you before October 1, 1985, and the Regional Director requests and retains the information.
(c) When you request reimbursement, you must identify reproduction and processing costs separately from acquisition costs.
(d) MMS will not reimburse you for data acquisition costs or for the costs of analyzing or processing geological information or interpreting geological or geophysical information.
[64 FR 72775, Dec. 28, 1999. Redesignated at 71 FR 23862, Apr. 25, 2006]
§ 250.197
Data and information to be made available to the public or for limited inspection.
MMS will protect data and information that you submit under this part, and part 203 of this chapter, as described in this section. Paragraphs (a) and (b) of this section describe what data and information will be made available to the public without the consent of the lessee, under what circumstances, and in what time period. Paragraph (c) of this section describes what data and information will be made available for limited inspection without the consent of the lessee, and under what circumstances.
(a) All data and information you submit on MMS forms will be made available to the public upon submission, except as specified in the following table:
On form . . . | Data and information not immediately available are . . . | Excepted data will be made available . . .
(1) MMS-123, Application for Permit to Drill | Items 15, 16, 22 through 25 | When the well goes on production or according to the table in paragraph (b) of this section, whichever is earlier.
(2) MMS-123S, Supplemental APD Information Sheet | Items 3, 7, 8, 15 and 17 | When the well goes on production or according to the table in paragraph (b) of this section, whichever is earlier.
(3) MMS-124, Application for Permit to Modify | Item 17 | When the well goes on production or according to the table in paragraph (b) of this section, whichever is earlier.
(4) MMS-125, End of Operations Report | Items 12, 13, 17, 21, 22, 26 through 38 | When the well goes on production or according to the table in paragraph (b) of this section, whichever is earlier. However, items 33 through 38 will not be released when the well goes on production unless the period of time in the table in paragraph (b) has expired.
(5) MMS-126, Well Potential Test Report | Item 101 | 2 years after you submit it.
(6) MMS-127, Sensitive Reservoir Information Report | Items 124 through 168 | 2 years after the effective date of the Sensitive Reservoir Information Report.
(7) MMS-133 Well Activity Report | Item 10 Fields [WELLBORE START DATE, TD DATE, OP STATUS, END DATE, MD, TVD, AND MW PPG]. Item 11 Fields [WELLBORE START DATE, TD DATE, PLUGBACK DATE, FINAL MD, AND FINAL TVD] and Items 12 through 15 | When the well goes on production or according to the table in paragraph (b) of this section, whichever is earlier.
(8) MMS-133S Open Hole Data Report | Boxes 7 and 8 | When the well goes on production or according to the table in paragraph (b) of this section, whichever is earlier.
(9) MMS-137 OCS Plan Information | Items providing the bottomhole location, true vertical depth, and measured depth of wells | When the well goes on production or according to the table in paragraph (b) of this section, whichever is earlier.
(10) MMS-140, Bottomhole Pressure Survey Report | All items | 2 years after the date of the survey.
(b) MMS will release lease and permit data and information that you submit and MMS retains, but that are not normally submitted on MMS forms, according to the following table:
If | MMS will release | At this time | Special provisions
(1) The Director determines that data and information are needed for specific scientific or research purposes for the Government | Geophysical data, Geological data Interpreted G&G information, Processed G&G information, Analyzed geological information | At any time | MMS will release data and information only if release would further the national interest without unduly damaging the competitive position of the lessee.
(2) Data or information is collected with high-resolution systems (e.g., bathymetry, side-scan sonar, subbottom profiler, and magnetometer) to comply with safety or environmental protection requirements | Geophysical data, Geological data, Interpreted G&G information, Processed geological information, Analyzed geological information | 60 days after MMS receives the data or information, if the Regional Supervisor deems it necessary | MMS will release the data and information earlier than 60 days if the Regional Supervisor determines it is needed by affected States to make decisions under subpart B. The Regional Supervisor will reconsider earlier release if you satisfy him/her that it would unduly damage your competitive position.
(3) Your lease is no longer in effect | Geophysical data, Geological data, Processed G&G information Interpreted G&G information, Analyzed geological information | When your lease terminates | This release time applies only if the provisions in this table governing high-resolution systems and the provisions in § 252.7 do not apply. The release time applies to the geophysical data and information only if acquired postlease for a lessee's exclusive use.
(4) Your lease is still in effect | Geophysical data Processed geophysical information, Interpreted G&G information | 10 years after you submit the data and information | This release time applies only if the provisions in this table governing high-resolution systems and the provisions in § 252.7 do not apply. This release time applies to the geophysical data and information only if acquired postlease for a lessee's exclusive use.
(5) Your lease is still in effect and within the primary term specified in the lease | Geological data, Analyzed geological information | 2 years after the required submittal date or 60 days after a lease sale if any portion of an offered lease is within 50 miles of a well, whichever is later | These release times apply only if the provisions in this table governing high-resolution systems and the provisions in § 252.7 do not apply. If the primary term specified in the lease is extended under the heading of “Suspensions” in this subpart, the extension applies to this provision.
(6) Your lease is in effect and beyond the primary term specified in the lease | Geological data, Analyzed geological information | 2 years after the required submittal date | None.
(7) Data or information is submitted on well operations | Descriptions of downhole locations, operations, and equipment | When the well goes on production or when geological data is released according to §§ 250.197(b)(5) and (b)(6), whichever occurs earlier | Directional survey data may be released earlier to the owner of an adjacent lease according to Subpart D of this part.
(8) Data and information are obtained from beneath unleased land as a result of a well deviation that has not been approved by the District Manager or Regional Supervisor | Any data or information obtained | At any time | None.
| (9) Except for high-resolution data and information released under paragraph (b)(2) of this section data and information acquired by a permit under part 251 are submitted by a lessee under 30 CFR part 203 or part 250 | G&G data, analyzed geological information, processed and interpreted G&G information | Geological data and information: 10 years after MMS issues the permit; Geophysical data: 50 years after MMS issues the permit; Geophysical information: 25 years after MMS issues the permit | None.
(c) MMS may allow limited inspection, but only by persons with a direct interest in related MMS decisions and issues in specific geographic areas, and who agree in writing to its confidentiality, of G&G data and information submitted under this part or part 203 of this chapter that MMS uses to:
(1) Make unitization determinations on two or more leases;
(2) Make competitive reservoir determinations;
(3) Ensure proper plans of development for competitive reservoirs;
(4) Promote operational safety;
(5) Protect the environment;
(6) Make field determinations; or
(7) Determine eligibility for royalty relief.
[64 FR 72775, Dec. 28, 1999, as amended at 71 FR 16039, Mar. 30, 2006. Redesignated and amended at 71 FR 23862, Apr. 25, 2006; 72 FR 25200, May 4, 2007]

References
§ 250.198
Documents incorporated by reference.
(a) MMS is incorporating by reference the documents listed in the table in paragraph (e) of this section. The Director of the Federal Register has approved this incorporation by reference according to 5 U.S.C. 552(a) and 1 CFR part 51.
(1) MMS will publish any changes to these documents in the Federal Register.
(2) MMS may make the rule amending the document effective without prior opportunity for public comment when MMS determines:
(i) That the revisions to a document result in safety improvements or represent new industry standard technology and do not impose undue costs on the affected parties; and
(ii) MMS meets the requirements for making a rule immediately effective under 5 U.S.C. 553.
(b) MMS incorporated each document or specific portion by reference in the sections noted. The entire document is incorporated by reference, unless the text of the corresponding sections in this part calls for compliance with specific portions of the listed documents. In each instance, the applicable document is the specific edition or specific edition and supplement or addendum cited in this section.
(c) Under §§ 250.141 and 250.142, you may comply with a later edition of a specific document incorporated by reference, provided:
(1) You show that complying with the later edition provides a degree of protection, safety, or performance equal to or better than would be achieved by compliance with the listed edition; and
(2) You obtain the prior written approval for alternative compliance from the authorized MMS official.
(d) You may inspect these documents at the Minerals Management Service, 381 Elden Street, Room 3313, Herndon, Virginia; or at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, call 202-741-6030, or go to: http://www.archives.gov/federal_register/code_of_federal_regulations/ibr_locations.html. You may obtain the documents from the publishing organizations at the addresses given in the following table:
For | Write to
(1) ACI Standards | American Concrete Institute, P. O. Box 9094, Farmington Hill, MI 48333-9094.
(2) AISC Standards | American Institute of Steel Construction, Inc., One East Wacker Drive, Suite #700, Chicago, IL 60601-1802.
(3) ANSI/ASME Codes | American National Standards Institute, ATTN: Sales Department, 25 West 43rd Street, 4th Floor, New York, NY 10036; and/or American Society of Mechanical Engineers, 22 Law Drive, P.O. Box 2900, Fairfield, NJ 07007-2900.
(4) API Recommended Practices, Specs, Standards, Manual of Petroleum Measurement Standards (MPMS) chapters | American Petroleum Institute, 1220 L Street, NW., Washington, DC 20005-4070.
(5) ASTM Standards | American Society for Testing and Materials, 100 Bar Harbor Drive, P. O. Box C700, West Conshohocken, PA 19428-2959.
(6) AWS Codes | American Welding Society, 550 NW, LeJeune Road, P.O. Box 351040, Miami, FL 33135.
(7) NACE Standards | National Association of Corrosion Engineers, First Services Dept., 1440 South Creek Drive, Houston, TX 77218.
(e) This paragraph lists documents incorporated by reference. To easily reference text of the corresponding sections with the list of documents incorporated by reference, the list is in alphanumerical order by organization and document.
Title of documents | Incorporated by reference at
ACI Standard 318-95, Building Code Requirements for Reinforced Concrete (ACI 318-95) and Commentary (ACI 318R-95) | § 250.901(a), (d).
ACI 357R-84, Guide for the Design and Construction of Fixed Offshore Concrete Structures, 1984; reapproved 1997 | § 250.901(a), (d).
ANSI/AISC 360-05, Specification for Structural Steel Buildings | § 250.901(a), (d).
ANSI/ASME Boiler and Pressure Vessel Code, Section I, Rules for Construction of Power Boilers; including Appendices 2004 Edition; and July 1, 2005 Addenda, Rules for Construction of Power Boilers, by ASME Boiler and Pressure Vessel Committee Subcommittee on Power Boilers; and all Section I Interpretations Volume 55 | § 250.803(b)(1), (b)(1)(i); § 250.1629(b)(1), (b)(1)(i).
ANSI/ASME Boiler and Pressure Vessel Code, Section IV, Rules for Construction of Heating Boilers; including Appendices 1, 2, 3, 5, 6, and Non-mandatory Appendices B, C, D, E, F, H, I, K, L, and M, and the Guide to Manufacturers Data Report Forms, 2004 Edition; July 1, 2005 Addenda, Rules for Construction of Heating Boilers, by ASME Boiler and Pressure Vessel Committee Subcommittee on Heating Boilers; and all Section IV Interpretations Volume 55 | § 250.803(b)(1), (b)(1)(i); § 250.1629(b)(1), (b)(1)(i).
ANSI/ASME Boiler and Pressure Vessel Code, Section VIII, Rules for Construction of Pressure Vessels; Divisions 1 and 2, 2004 Edition; July 1, 2005 Addenda, Divisions 1 and 2, Rules for Construction of Pressure Vessels, by ASME Boiler and Pressure Vessel Committee Subcommittee on Pressure Vessels; and all Section VIII Interpretations Volumes 54 and 55 | § 250.803(b)(1), (b)(1)(i); § 250.1629(b)(1), (b)(1)(i).
ANSI/ASME B 16.5-2003, Pipe Flanges and Flanged Fittings | § 250.1002(b)(2).
ANSI/ASME B 31.8-2003, Gas Transmission and Distribution Piping Systems | § 250.1002(a).
ANSI/ASME SPPE-1-1994 and SPPE-1d-1996 Addenda, Quality Assurance and Certification of Safety and Pollution Prevention Equipment Used in Offshore Oil and Gas Operations | § 250.806(a)(2)(i).
ANSI Z88.2-1992, American National Standard for Respiratory Protection | § 250.490(g)(4)(iv), (j)(13)(ii).
API 510, Pressure Vessel Inspection Code: In-Service Inspection, Rating, Repair, and Alteration, Downstream Segment, Ninth Edition, June 2006, API Stock No. C51009 | § 250.803(b)(1); § 250.1629(b)(1).
API Bulletin 2INT-DG, Interim Guidance for Design of Offshore Structures for Hurricane Conditions, May 2007 | § 250.901(a), (d).
API Bulletin 2INT-EX, Interim Guidance for Assessment of Existing Offshore Structures for Hurricane Conditions, May 2007 | § 250.901(a), (d).
API Bulletin 2INT-MET, Interim Guidance on Hurricane Conditions in the Gulf of Mexico, May 2007 | § 250.901(a), (d).
API MPMS, Chapter 1—Vocabulary, Second Edition, July 1994, API Stock No. H01002 | § 250.1201.
API MPMS, Chapter 2—Tank Calibration, Section 2A—Measurement and Calibration of Upright Cylindrical Tanks by the Manual Tank Strapping Method, First Edition, February 1995; reaffirmed March 2002, API Stock No. H022A1 | § 250.1202(l)(4).
API MPMS, Chapter 2—Tank Calibration, Section 2B—Calibration of Upright Cylindrical Tanks Using the Optical Reference Line Method, First Edition, March 1989; reaffirmed March 2002, API Stock No. H30023 | § 250.1202(l)(4).
API MPMS, Chapter 3—Tank Gauging, Section 1A—Standard Practice for the Manual Gauging of Petroleum and Petroleum Products, Second Edition, August 2005, API Stock No. H301A02 | § 250.1202(l)(4).
API MPMS, Chapter 3—Tank Gauging, Section 1B—Standard Practice for Level Measurement of Liquid Hydrocarbons in Stationary Tanks by Automatic Tank Gauging, Second Edition, June 2001, API Stock No. H301B2 | § 250.1202(l)(4).
| API MPMS, Chapter 4—Proving Systems, Section 1—Introduction, Third Edition, February 2005, API Stock No. H04013 | § 250.1202(a)(3), (f)(1).
API MPMS, Chapter 4—Proving Systems, Section 2—Displacement Provers, Third Edition, September 2003, API Stock No. H04023 | § 250.1202(a)(3), (f)(1).
API MPMS, Chapter 4—Proving Systems, Section 4—Tank Provers, Second Edition, May 1998, API Stock No. H04042 | § 250.1202(a)(3), (f)(1).
API MPMS, Chapter 4—Proving Systems, Section 5—Master-Meter Provers, Second Edition, May 2000, API Stock No. H04052 | § 250.1202(a)(3), (f)(1).
API MPMS, Chapter 4—Proving Systems, Section 6—Pulse Interpolation, Second Edition, July 1999; reaffirmed 2003, API Stock No. H06042 | § 250.1202(a)(3), (f)(1).
API MPMS, Chapter 4—Proving Systems, Section 7—Field Standard Test Measures, Second Edition, December 1998; reaffirmed 2003, API Stock No. H04072 | § 250.1202(a)(3), (f)(1).
API MPMS, Chapter 5—Metering, Section 1—General Considerations for Measurement by Meters, Measurement Coordination Department, Fourth Edition, September 2005, API Stock No. H05014 | § 250.1202(a)(3).
API MPMS, Chapter 5—Metering, Section 2—Measurement of Liquid Hydrocarbons by Displacement Meters, Third Edition, September 2005, API Stock No. H05023 | § 250.1202(a)(3).
API MPMS Chapter 5—Metering, Section 3—Measurement of Liquid Hydrocarbons by Turbine Meters, Fifth Edition, September 2005, API Stock No. H05035 | § 250.1202(a)(3).
API MPMS, Chapter 5—Metering, Section 4—Accessory Equipment for Liquid Meters, Fourth Edition, September 2005, API Stock No. H05044 | § 250.1202(a)(3).
API MPMS, Chapter 5—Metering, Section 5—Fidelity and Security of Flow Measurement Pulsed-Data Transmission Systems, Second Edition, August 2005, API Stock No. H50502 | § 250.1202(a)(3).
API MPMS, Chapter 6—Metering Assemblies, Section 1—Lease Automatic Custody Transfer (LACT) Systems, Second Edition, May 1991; reaffirmed March 2002, API Stock No. H30121 | § 250.1202(a)(3).
API MPMS, Chapter 6—Metering Assemblies, Section 6—Pipeline Metering Systems, Second Edition, May 1991; reaffirmed March 2002, API Stock No. H30126 | § 250.1202(a)(3).
API MPMS, Chapter 6—Metering Assemblies, Section 7—Metering Viscous Hydrocarbons, Second Edition, May 1991; reaffirmed March 2002, API Stock No. H30127 | § 250.1202(a)(3).
API MPMS, Chapter 7—Temperature Determination, Measurement Coordination, First Edition, June 2001, API Stock No. H07001 | § 250.1202(a)(3), (l)(4).
API MPMS, Chapter 8—Sampling, Section 1—Standard Practice for Manual Sampling of Petroleum and Petroleum Products, Third Edition, October 1995; reaffirmed March 2006, API Stock No. H30161 | § 250.1202(b)(4)(i), (l)(4).
API MPMS, Chapter 8—Sampling, Section 2—Standard Practice for Automatic Sampling of Liquid Petroleum and Petroleum Products, Second Edition, October 1995; reaffirmed June 2005, API Stock No. H08022 | § 250.1202(a)(3), (l)(4).
API MPMS, Chapter 9—Density Determination, Section 1—Standard Test Method for Density, Relative Density (Specific Gravity), or API Gravity of Crude Petroleum and Liquid Petroleum Products by Hydrometer Method, Second Edition, December 2002; reaffirmed October 2005, API Stock No. H09012 | § 250.1202(a)(3), (l)(4).
API MPMS, Chapter 9—Density Determination, Section 2—Standard Test Method for Density or Relative Density of Light Hydrocarbons by Pressure Hydrometer, Second Edition, March 2003, API Stock No. H09022 | § 250.1202(a)(3), (l)(4).
API MPMS, Chapter 10—Sediment and Water, Section 1—Standard Test Method for Sediment in Crude Oils and Fuel Oils by the Extraction Method, Second Edition, October 2002, API Stock No. H10012 | § 250.1202(a)(3), (l)(4).
API MPMS, Chapter 10—Sediment and Water, Section 2—Determination of Water in Crude Oil by Distillation Method, First Edition, April 1981; reaffirmed 2005, API Stock No. H30202 | § 250.1202(a)(3), (l)(4).
API MPMS, Chapter 10—Sediment and Water, Section 3—Standard Test Method for Water and Sediment in Crude Oil by the Centrifuge Method (Laboratory Procedure), Second Edition, May 2003, API Stock No. H10032 | § 250.1202(a)(3), (l)(4).
API MPMS, Chapter 10—Sediment and Water, Section 4—Determination of Water and/or Sediment in Crude Oil by the Centrifuge Method (Field Procedure), Third Edition, December 1999, API Stock No. H10043 | § 250.1202(a)(3), (l)(4).
API MPMS, Chapter 10—Sediment and Water, Section 9—Standard Test Method for Water in Crude Oils by Coulometric Karl Fischer Titration, Second Edition, December 2002; reaffirmed 2005, API Stock No. H10092 | § 250.1202(a)(3), (l)(4).
API MPMS, Chapter 11.1—Volume Correction Factors, Volume 1, Table 5A—Generalized Crude Oils and JP-4 Correction of Observed API Gravity to API Gravity at 60 °F, and Table 6A—Generalized Crude Oils and JP-4 Correction of Volume to 60 °F Against API Gravity at 60 °F, API Standard 2540, First Edition, August 1980; reaffirmed March 1997, API Stock No. H27000 | § 250.1202(a)(3), (g)(3), (l)(4).
API MPMS, Chapter 11.2.2—Compressibility Factors for Hydrocarbons: 0.350-0.637 Relative Density (60 °F/60 °F) and −50 °F to 140 °F Metering Temperature, Second Edition, October 1986; reaffirmed December 2002, API Stock No. H27307 | § 250.1202(a)(3), (g)(4).
API MPMS, Chapter 11—Physical Properties Data, Addendum to Section 2, Part 2—Compressibility Factors for Hydrocarbons, Correlation of Vapor Pressure for Commercial Natural Gas Liquids, First Edition, December 1994; reaffirmed December 2002, API Stock No. H27308 | § 250.1202(a)(3).
| API MPMS, Chapter 12—Calculation of Petroleum Quantities, Section 2—Calculation of Petroleum Quantities Using Dynamic Measurement Methods and Volumetric Correction Factors, Part 1—Introduction, Second Edition, May 1995; reaffirmed March 2002, API Stock No. 852-12021 | § 250.1202(a)(3), (g)(1), (g)(2).
API MPMS, Chapter 12—Calculation of Petroleum Quantities, Section 2—Calculation of Petroleum Quantities Using Dynamic Measurement Methods and Volumetric Correction Factors, Part 2—Measurement Tickets, Third Edition, June 2003, API Stock No. H12223 | § 250.1202(a)(3), (g)(1), (g)(2)
API MPMS, Chapter 14—Natural Gas Fluids Measurement, Section 3—Concentric, Square-Edged Orifice Meters, Part 1—General Equations and Uncertainty Guidelines, Third Edition, September 1990; reaffirmed January 2003, API Stock No. H30350 | § 250.1203(b)(2).
API MPMS, Chapter 14—Natural Gas Fluids Measurement, Section 3—Concentric, Square-Edged Orifice Meters, Part 2—Specification and Installation Requirements, Fourth Edition, April 2000; reaffirmed March 2006, API Stock No. H30351 | § 250.1203(b)(2).
API MPMS, Chapter 14—Natural Gas Fluids Measurement, Section 3—Concentric, Square-Edged Orifice Meters, Part 3—Natural Gas Applications, Third Edition, August 1992; reaffirmed January 2003, API Stock No. H30353 | § 250.1203(b)(2).
API MPMS, Chapter 14.5—Calculation of Gross Heating Value, Relative Density and Compressibility Factor for Natural Gas Mixtures from Compositional Analysis, Second Edition, revised 1996; reaffirmed March 2002, API Stock No. H14052 | § 250.1203(b)(2).
API MPMS, Chapter 14—Natural Gas Fluids Measurement, Section 6—Continuous Density Measurement, Second Edition, April 1991; reaffirmed February 2006, API Stock No. H30346 | § 250.1203(b)(2).
API MPMS, Chapter 14—Natural Gas Fluids Measurement, Section 8—Liquefied Petroleum Gas Measurement, Second Edition, July 1997; reaffirmed March 2002, API Stock No. H14082 | § 250.1203(b)(2).
API MPMS, Chapter 20—Section 1—Allocation Measurement, First Edition, August 1993; reaffirmed October 2006, API Stock No. H30701 | § 250.1202(k)(1).
API MPMS, Chapter 21—Flow Measurement Using Electronic Metering Systems, Section 1—Electronic Gas Measurement, First Edition, August 1993; reaffirmed July 2005, API Stock No. H30730 | § 250.1203(b)(4).
API RP 2A-WSD, Recommended Practice for Planning, Designing and Constructing Fixed Offshore Platforms—Working Stress Design, Twenty-first Edition, December 2000; Errata and Supplement 1, December 2002; Errata and Supplement 2, October 2005, API Stock No. G2AWSD | § 250.901(a), (d); § 250.908(a); § 250.920(a), (b), (c), (e).
API RP 2D, Recommended Practice for Operation and Maintenance of Offshore Cranes, Fifth Edition, June 2003, API Stock No. G02D05 | § 250.108(a).
API RP 2FPS, RP for Planning, Designing, and Constructing, Floating Production Systems | § 250.901(a), (d).
API RP 2RD, Recommended Practice for Design of Risers for Floating Production Systems (FPSs) and Tension-Leg Platforms (TLPs), First Edition, June 1998; reaffirmed May 2006, API Stock No. G02RD1 | § 250.800(b)(2); § 250.901(a), (d); § 250.1002(b)(5).
API RP 2SK, Recommended Practice for Design and Analysis of Stationkeeping Systems for Floating Structures, Third Edition, October 2005, API Stock No. G2SK03 | § 250.800(b)(3); § 250.901(a), (d).
API RP 2SM, Recommended Practice for Design, Manufacture, Installation, and Maintenance of Synthetic Fiber Ropes for Offshore Mooring, First Edition, March 2001, API Stock No. G02SM1 | § 250.901(a), (d).
API RP 2T, Recommended Practice for Planning, Designing, and Constructing Tension Leg Platforms, Second Edition, August 1997, API Stock No. G02T02 | § 250.901(a), (d).
API RP 14B, Recommended Practice for Design, Installation, Repair and Operation of Subsurface Safety Valve Systems, Fifth Edition, October 2005, also available as ISO 10417: 2004, (Identical) Petroleum and natural gas industries—Subsurface safety valve systems—Design, installation, operation and redress, API Stock No. GX14B05 | § 250.801(e)(4); § 250.804(a)(1)(i).
API RP 14C, Recommended Practice for Analysis, Design, Installation, and Testing of Basic Surface Safety Systems for Offshore Production Platforms, Seventh Edition, March 2001, API Stock No. C14C07 | § 250.125(a); § 250.292(j); § 250.802(b), (e)(2); § 250.803(a), (b)(2)(i), (b)(4), (b)(5)(i), (b)(7), (b)(9)(v), (c)(2); § 250.804(a), (a)(6); § 250.1002(d); § 250.1004(b)(9); § 250.1628(c), (d)(2); § 250.1629(b)(2), (b)(4)(v); § 250.1630(a).
API RP 14E, Recommended Practice for Design and Installation of Offshore Production Platform Piping Systems, Fifth Edition, October 1, 1991; reaffirmed June 2000, API Stock No. G07185 | § 250.802(e)(3); § 250.1628(b)(2), (d)(3).
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, Fourth Edition, June 1999, API Stock No. G14F04 | § 250.114(c); § 250.803(b)(9)(v); § 250.1629(b)(4)(v).
API RP 14FZ, Recommended Practice for Design and Installation of Electrical Systems for Fixed and Floating Offshore Petroleum Facilities for Unclassified and Class I, Zone 0, Zone 1 and Zone 2 Locations, First Edition, September 2001, API Stock No. G14FZ1 | § 250.114(c); § 250.803(b)(9)(v); § 250.1629(b)(4)(v).
API RP 14G, Recommended Practice for Fire Prevention and Control on Open Type Offshore Production Platforms, Third Edition, December 1, 1993; reaffirmed June 2000, API Stock No. G07194 | § 250.803(b)(8), (b)(9)(v); § 250.1629(b)(3), (b)(4)(v).
| API RP 14H, Recommended Practice for Installation, Maintenance, and Repair of Surface Safety Valves and Underwater Safety Valves Offshore, Fourth Edition, July 1, 1994, API Stock No. G14H04 | § 250.802(d); § 250.804(a)(5).
API RP 14J, Recommended Practice for Design and Hazards Analysis for Offshore Production Facilities, Second Edition, May 2001, API Stock No. G14J02 | § 250.800(b)(1); § 250.901(a)(10).
API RP 53, Recommended Practices for Blowout Prevention Equipment Systems for Drilling Wells, Third Edition, March 1997; reaffirmed September 2004, API Stock No. G53003 | § 250.442(c); § 250.446(a).
API RP 65, Recommended Practice for Cementing Shallow Water Flow Zones in Deep Water Wells, First Edition, September 2002, API Stock No. G56001 | § 250.198; § 250.415(e).
API RP 500, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Division 1 and Division 2, Second Edition, November 1997; reaffirmed November 2002, API Stock No. C50002 | § 250.114(a); § 250.459; § 250.802(e)(4)(i); § 250.803(b)(9)(i); § 250.1628(b)(3), (d)(4)(i); § 250.1629(b)(4)(i).
API RP 505, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Zone 0, Zone 1, and Zone 2, First Edition, November 1997; reaffirmed November 2002, API Stock No. C50501 | § 250.114(a); § 250.459; § 250.802(e)(4)(i); § 250.803(b)(9)(i); § 250.1628(b)(3), (d)(4)(i); § 250.1629(b)(4)(i).
API RP 2556, Recommended Practice for Correcting Gauge Tables for Incrustation, Second Edition, August 1993; reaffirmed November 2003, API Stock No. H25560 | § 250.1202(l)(4).
API Spec. Q1, Specification for Quality Programs for the Petroleum, Petrochemical and Natural Gas Industry, ANSI/API Specification Q1, Seventh Edition, June 15, 2003; also available as ISO/TS 29001, Effective Date: December 15, 2003, API Stock No. GQ1007 | § 250.806(a)(2)(ii).
API Spec. 2C, Specification for Offshore Pedestal Mounted Cranes, Sixth Edition, March 2004, Effective Date: September 2004, API Stock No. G02C06 | § 250.108(c), (d).
API Spec. 6A, Specification for Wellhead and Christmas Tree Equipment, ANSI/API Specification 6A, Nineteenth Edition, July 2004; also available as ISO 10423:2003, (Modified) Petroleum and natural gas industries—Drilling and production equipment—Wellhead and Christmas tree equipment, Effective Date: February 1, 2005; Errata 1, September 1, 2004, API Stock No. GX06A19 | § 250.806(a)(3); § 250.1002 (b)(1), (b)(2).
API Spec. 6AV1, Specification for Verification Test of Wellhead Surface Safety Valves and Underwater Safety Valves for Offshore Service, First Edition, February 1, 1996; reaffirmed January 2003, API Stock No. G06AV1 | § 250.806(a)(3).
API Spec. 6D, Specification for Pipeline Valves, Twenty-second Edition, January 2002; also available as ISO 14313:1999, MOD, Petroleum and natural gas industries—Pipeline transportation systems—Pipeline valves, Effective Date: July 1, 2002, Proposed National Adoption, includes Annex F, March 1, 2005, API Stock No. G06D22 | § 250.1002(b)(1).
API Spec. 14A, Specification for Subsurface Safety Valve Equipment, Tenth Edition, November 2000; also available as ISO 10432:1999, Petroleum and natural gas industries—Downhole equipment—Subsurface safety valve equipment, Effective Date: May 15, 2001, API Stock No. GG14A10 | § 250.806(a)(3).
API Spec. 17J, Specification for Unbonded Flexible Pipe, Second Edition, November 1999; Errata dated May 25, 2001; Addendum 1, June 2003, Effective Date: December 2002, API Stock No. G17J02 | § 250.803(b)(2)(iii); § 250.1002(b)(4); § 250.1007(a)(4).
API Standard 2551, Measurement and Calibration of Horizontal Tanks, First Edition, 1965; reaffirmed March 2002, API Stock No. H25510 | § 250.1202(l)(4).
API Standard 2552, USA Standard Method for Measurement and Calibration of Spheres and Spheroids, First Edition, 1966; reaffirmed February 2006, API Stock No. H25520 | § 250.1202(l)(4).
API Standard 2555, Method for Liquid Calibration of Tanks, First Edition, September 1966; reaffirmed March 2002; API Stock No. H25550 | § 250.1202(l)(4).
ASTM Standard C 33-99a, Standard Specification for Concrete Aggregates | § 250.901(a), (d).
ASTM Standard C 94/C 94M-99, Standard Specification for Ready-Mixed Concrete | § 250.901(a), (d).
ASTM Standard C 150-99, Standard Specification for Portland Cement | § 250.901(a), (d).
ASTM Standard C 330-99, Standard Specification for Lightweight Aggregates for Structural Concrete | § 250.901(a), (d).
ASTM Standard C 595-98, Standard Specification for Blended Hydraulic Cements | § 250.901(a), (d).
AWS D1.1:2000, Structural Welding Code—Steel | § 250.901(a), (d).
AWS D1.4-98, Structural Welding Code—Reinforcing Steel | § 250.901(a), (d).
AWS D3.6M:1999, Specification for Underwater Welding | § 250.901(a), (d).
NACE Standard MR0175-2003, Item No. 21302, Standard Material Requirements, Metals for Sulfide Stress Cracking and Stress Corrosion Cracking Resistance in Sour Oilfield Environments | § 250.901(a), § 250.490(p)(2).
NACE Standard RP0176-2003, Item No. 21018, Standard Recommended Practice, Corrosion Control of Steel Fixed Offshore Structures Associated with Petroleum Production | § 250.901(a), (d).
[64 FR 72775, Dec. 28, 1999, as amended at 65 FR 218, 219, Jan. 4, 2000; 65 FR 3127, Jan. 20, 2000; 65 FR 14470, Mar. 17, 2000; 65 FR 15863, Mar. 24, 2000; 65 FR 18432, Apr. 7, 2000; 65 FR 25285, May 1, 2000; 65 FR 36328, June 8, 2000; 65 FR 40052, June 29, 2000; 65 FR 41002, July 3, 2000; 65 FR 76935, Dec. 8, 2000; 67 FR 51759, Aug. 9, 2002; 68 FR 46, Jan. 2, 2003; 68 FR 7427, Feb. 14, 2003; 68 FR 8422, Feb. 20, 2003; 68 FR 19355, Apr. 21, 2003; 68 FR 43298, July 22, 2003; 69 FR 18803, Apr. 9, 2004; 70 FR 7403, Feb. 14, 2005; 70 FR 41573, July 19, 2005; 72 FR 12092, Mar. 15, 2007; 72 FR 25200, May 4, 2007; 73 FR 20168, Apr. 15, 2008]
§ 250.199
Paperwork Reduction Act statements—information collection.
(a) OMB has approved the information collection requirements in part 250 under 44 U.S.C. 3501 et seq. The table in paragraph (e) of this section lists the subpart in the rule requiring the information and its title, provides the OMB control number, and summarizes the reasons for collecting the information and how MMS uses the information. The associated MMS forms required by this part are listed at the end of this table with the relevant information.
(b) Respondents are OCS oil, gas, and sulphur lessees and operators. The requirement to respond to the information collections in this part is mandated under the Act (43 U.S.C. 1331 et seq.) and the Act's Amendments of 1978 (43 U.S.C. 1801 et seq.). Some responses are also required to obtain or retain a benefit or may be voluntary. Proprietary information will be protected under § 250.197, Data and information to be made available to the public; parts 251 and 252; and the Freedom of Information Act (5 U.S.C. 552) and its implementing regulations at 43 CFR part 2.
(c) The Paperwork Reduction Act of 1995 requires us to inform the public that an agency may not conduct or sponsor, and you are not required to respond to, a collection of information unless it displays a currently valid OMB control number.
(d) Send comments regarding any aspect of the collections of information under this part, including suggestions for reducing the burden, to the Information Collection Clearance Officer, Minerals Management Service, Mail Stop 4230, 1849 C Street, NW., Washington, DC 20240.
(e) MMS is collecting this information for the reasons given in the following table:
30 CFR subpart, title and/or MMS Form (OMB Control No.) | Reasons for collecting information and how used
(1) Subpart A, General (1010-0114), including Forms MMS-132, Evacuation Statistics; MMS-1123, Designation of Operator; MMS-1832, Notification of Incidents of Noncompliance | To inform MMS of actions taken to comply with general operational requirements on the OCS. To ensure that operations on the OCS meet statutory and regulatory requirements, are safe and protect the environment, and result in diligent exploration, development, and production on OCS leases. To support the unproved and proved reserve estimation, resource assessment, and fair market value determinations.
(2) Subpart B, Exploration and Development and Production Plans (1010-0151), including Forms MMS-137, OCS Plan Information Form; MMS-139, EP Air Quality Screening Checklist; MMS-138, DOCD Air Quality Screening Checklist, MMS-141, ROV Survey Report Form; MMS-142, Environmental Impact Analysis Worksheet | To inform MMS, States, and the public of planned exploration, development, and production operations on the OCS. To ensure that operations on the OCS are planned to comply with statutory and regulatory requirements, will be safe and protect the human, marine, and coastal environment, and will result in diligent exploration, development, and production of leases.
(3) Subpart C, Pollution Prevention and Control (1010-0057) | To inform MMS of measures to be taken to prevent water and air pollution. To ensure that appropriate measures are taken to prevent water and air pollution.
(4) Subpart D, Oil and Gas and Drilling Operations (1010-0141), including Forms MMS-123, Application for Permit to Drill; MMS-123S, Supplemental APD Information Sheet; MMS-124, Application for Permit to Modify; MMS-125, End of Operations Report; MMS-133, Well Activity Report; MMS-133S, Open Hole Data Report | To inform MMS of the equipment and procedures to be used in drilling operations on the OCS. To ensure that drilling operations are safe and protect the human, marine, and coastal environment.
(5) Subpart E, Oil and Gas Well-Completion Operations (1010-0067) | To inform MMS of the equipment and procedures to be used in well-completion operations on the OCS. To ensure that well-completion operations are safe and protect the human, marine, and coastal environment.
| (6) Subpart F, Oil and Gas Well Workover Operations (1010-0043) | To inform MMS of the equipment and procedures to be used during well-workover operations on the OCS. To ensure that well-workover operations are safe and protect the human, marine, and coastal environment.
(7) Subpart H, Oil and Gas Production Safety Systems (1010-0059) | To inform MMS of the equipment and procedures to be used during production operations on the OCS. To ensure that production operations are safe and protect the human, marine, and coastal environment.
(8) Subpart I, Platforms and Structures (1010-0149) | To provide MMS with information regarding the design, fabrication, and installation of platforms on the OCS. To ensure the structural integrity of platforms installed on the OCS.
(9) Subpart J, Pipelines and Pipeline Rights-of-Way (1010-0050) | To provide MMS with information regarding the design, installation, and operation of pipelines on the OCS. To ensure that pipeline operations are safe and protect the human, marine, and coastal environment.
(10) Subpart K, Oil and Gas Production Rates (1010-0041), including Forms MMS-126, Well Potential Test Report; MMS-127, Sensitive Reservoir Information Report; MMS-128, Semiannual Well Test Report; MMS-140 Bottomhole Pressure Survey Report | To inform MMS of production rates for hydrocarbons produced on the OCS. To ensure economic maximization of ultimate hydrocarbon recovery.
(11) Subpart L, Oil and Gas Production Measurement, Surface Commingling, and Security (1010-0051) | To inform MMS of the measurement of production, commingling of hydrocarbons, and site security plans. To ensure that produced hydrocarbons are measured and commingled to provide for accurate royalty payments and security is maintained.
(12) Subpart M, Unitization (1010-0068) | To inform MMS of the unitization of leases. To ensure that unitization prevents waste, conserves natural resources, and protects correlative rights.
(13) Subpart N, Remedies and Penalties | The requirements in subpart N are exempt from the Paperwork Reduction Act of 1995 according to 5 CFR 1320.4.
(14) Subpart O, Well Control and Production Safety Training (1010-0128) | To inform MMS of training program curricula, course schedules, and attendance. To ensure that training programs are technically accurate and sufficient to meet safety and environmental requirements, and that workers are properly trained to operate on the OCS.
(15) Subpart P, Sulphur Operations (1010-0086) | To inform MMS of sulphur exploration and development operations on the OCS. To ensure that OCS sulphur operations are safe; protect the human, marine, and coastal environment; and will result in diligent exploration, development, and production of sulphur leases.
(16) Subpart Q, Decommissioning Activities (1010-0142) | To determine that decommissioning activities comply with regulatory requirements and approvals. To ensure that site clearance and platform or pipeline removal are properly performed to protect marine life and the environment and do not conflict with other users of the OCS.
(17) Form MMS-131, Performance Measures (1010-0112) | Voluntary. We use the information obtained from this form to develop an industry average that helps to describe how well the offshore oil and gas industry is performing.
(18) Form MMS-144, Rig Movement Notification Report (form used in the GOM OCS Region), Subparts D, E, F, (1010-0150) | The rig notification requirement is essential for MMS inspection scheduling and to verify that the equipment being used complies with approved permits.
[64 FR 72775, Dec. 28, 1999, as amended at 67 FR 35405, May 17, 2002; 68 FR 8422, Feb. 20, 2003; 71 FR 23863, Apr. 25, 2006; 72 FR 25200, May 4, 2007]

Subpart B—Plans and Information

Source:
70 FR 51501, Aug. 30, 2005, unless otherwise noted.

General Information
§ 250.200
Definitions.
Acronyms and terms used in this subpart have the following meanings:
(a) Acronyms used frequently in this subpart are listed alphabetically below:
CID means Conservation Information Document
CZMA means Coastal Zone Management Act
DOCD means Development Operations Coordination Document
DPP means Development and Production Plan
DWOP means Deepwater Operations Plan
EIA means Environmental Impact Analysis
EP means Exploration Plan
MMS means Minerals Management Service
NPDES means National Pollutant Discharge Elimination System
NTL means Notice to Lessees and Operators
OCS means Outer Continental Shelf
(b) Terms used in this subpart are listed alphabetically below:
Amendment means a change you make to an EP, DPP, or DOCD that is pending before MMS for a decision (see §§ 250.232(d) and 250.267(d)).
Modification means a change required by the Regional Supervisor to an EP, DPP, or DOCD (see § 250.233(b)(2) and § 250.270(b)(2)) that is pending before MMS for a decision because the OCS plan is inconsistent with applicable requirements.
New or unusual technology means equipment or procedures that:
(1) Have not been used previously or extensively in an MMS OCS Region;
(2) Have not been used previously under the anticipated operating conditions; or
(3) Have operating characteristics that are outside the performance parameters established by this part.
Non-conventional production or completion technology includes, but is not limited to, floating production systems, tension leg platforms, spars, floating production, storage, and offloading systems, guyed towers, compliant towers, subsea manifolds, and other subsea production components that rely on a remote site or host facility for utility and well control services.
Offshore vehicle means a vehicle that is capable of being driven on ice.
Resubmitted OCS plan means an EP, DPP, or DOCD that contains changes you make to an OCS plan that MMS has disapproved (see §§ 250.234(b), 250.272(a), and 250.273(b)).
Revised OCS plan means an EP, DPP, or DOCD that proposes changes to an approved OCS plan, such as those in the location of a well or platform, type of drilling unit, or location of the onshore support base (see § 250.283(a)).
Supplemental OCS plan means an EP, DPP, or DOCD that proposes the addition to an approved OCS plan of an activity that requires approval of an application or permit (see § 250.283(b)).
§ 250.201
What plans and information must I submit before I conduct any activities on my lease or unit?
(a) Plans and documents. Before you conduct the activities on your lease or unit listed in the following table, you must submit, and MMS must approve, the listed plans and documents. Your plans and documents may cover one or more leases or units.
You must submit a(n) . . . | Before you . . .
(1) Exploration Plan (EP) | Conduct any exploration activities on a lease or unit.
(2) Development and Production Plan (DPP) | Conduct any development and production activities on a lease or unit in any OCS area other than the Western Gulf of Mexico.
(3) Development Operations Coordination Document (DOCD) | Conduct any development and production activities on a lease or unit in the Western GOM.
(4) Deepwater Operations Plan (DWOP) | Conduct post-drilling installation activities in any water depth associated with a development project that will involve the use of a non-conventional production or completion technology.
(5) Conservation Information Document (CID) | Commence production from development projects in water depths greater than 1,312 feet (400 meters).
(6) EP, DPP, or DOCD | Conduct geological or geophysical (G&G) exploration or a development G&G activity (see definitions under § 250.105) on your lease or unit when:
| (i) It will result in a physical penetration of the seabed greater than 500 feet (152 meters);
| (ii) It will involve the use of explosives;
| (iii) The Regional Director determines that it might have a significant adverse effect on the human, marine, or coastal environment; or
| (iv) The Regional Supervisor, after reviewing a notice under § 250.209, determines that an EP, DPP, or DOCD is necessary.
(b) Submitting additional information. On a case-by-case basis, the Regional Supervisor may require you to submit additional information if the Regional Supervisor determines that it is necessary to evaluate your proposed plan or document.
(c) Limiting information. The Regional Director may limit the amount of information or analyses that you otherwise must provide in your proposed plan or document under this subpart when:
(1) Sufficient applicable information or analysis is readily available to MMS;
(2) Other coastal or marine resources are not present or affected;
(3) Other factors such as technological advances affect information needs; or
(4) Information is not necessary or required for a State to determine consistency with their CZMA Plan.
(d) Referencing. In preparing your proposed plan or document, you may reference information and data discussed in other plans or documents you previously submitted or that are otherwise readily available to MMS.
[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 25200, May 4, 2007]
§ 250.202
What criteria must the Exploration Plan (EP), Development and Production Plan (DPP), or Development Operations Coordination Document (DOCD) meet?
Your EP, DPP, or DOCD must demonstrate that you have planned and are prepared to conduct the proposed activities in a manner that:
(a) Conforms to the Outer Continental Shelf Lands Act as amended (Act), applicable implementing regulations, lease provisions and stipulations, and other Federal laws;
(b) Is safe;
(c) Conforms to sound conservation practices and protects the rights of the lessor;
(d) Does not unreasonably interfere with other uses of the OCS, including those involved with national security or defense; and
(e) Does not cause undue or serious harm or damage to the human, marine, or coastal environment.
§ 250.203
Where can wells be located under an EP, DPP, or DOCD?
The Regional Supervisor reviews and approves proposed well location and spacing under an EP, DPP, or DOCD. In deciding whether to approve a proposed well location and spacing, the Regional Supervisor will consider factors including, but not limited to, the following:
(a) Protecting correlative rights;
(b) Protecting Federal royalty interests;
(c) Recovering optimum resources;
(d) Number of wells that can be economically drilled for proper reservoir management;
(e) Location of drilling units and platforms;
(f) Extent and thickness of the reservoir;
(g) Geologic and other reservoir characteristics;
(h) Minimizing environmental risk;
(i) Preventing unreasonable interference with other uses of the OCS; and
(j) Drilling of unnecessary wells.
§ 250.204
How must I protect the rights of the Federal government?
(a) To protect the rights of the Federal government, you must either:
(1) Drill and produce the wells that the Regional Supervisor determines are necessary to protect the Federal government from loss due to production on other leases or units or from adjacent lands under the jurisdiction of other entities (e.g., State and foreign governments); or
(2) Pay a sum that the Regional Supervisor determines as adequate to compensate the Federal government for your failure to drill and produce any well.
(b) Payment under paragraph (a)(2) of this section may constitute production in paying quantities for the purpose of extending the lease term.
(c) You must complete and produce any penetrated hydrocarbon-bearing zone that the Regional Supervisor determines is necessary to conform to sound conservation practices.
§ 250.205
Are there special requirements if my well affects an adjacent property?
For wells that could intersect or drain an adjacent property, the Regional Supervisor may require special measures to protect the rights of the Federal government and objecting lessees or operators of adjacent leases or units.
§ 250.206
How do I submit the EP, DPP, or DOCD?
(a) Number of copies. When you submit an EP, DPP, or DOCD to MMS, you must provide:
(1) Four copies that contain all required information (proprietary copies);
(2) Eight copies for public distribution (public information copies) that omit information that you assert is exempt from disclosure under the Freedom of Information Act (FOIA) (5 U.S.C. 552) and the implementing regulations (43 CFR part 2); and
(3) Any additional copies that may be necessary to facilitate review of the EP, DPP, or DOCD by certain affected States and other reviewing entities.
(b) Electronic submission. You may submit part or all of your EP, DPP, or DOCD and its accompanying information electronically. If you prefer to submit your EP, DPP, or DOCD electronically, ask the Regional Supervisor for further guidance.
(c) Withdrawal after submission. You may withdraw your proposed EP, DPP, or DOCD at any time for any reason. Notify the appropriate MMS OCS Region if you do.

Ancillary Activities
§ 250.207
What ancillary activities may I conduct?
Before or after you submit an EP, DPP, or DOCD to MMS, you may elect, the regulations in this part may require, or the Regional Supervisor may direct you to conduct ancillary activities. Ancillary activities include:
(a) Geological and geophysical (G&G) explorations and development G&G activities;
(b) Geological and high-resolution geophysical, geotechnical, archaeological, biological, physical oceanographic, meteorological, socioeconomic, or other surveys; or
(c) Studies that model potential oil and hazardous substance spills, drilling muds and cuttings discharges, projected air emissions, or potential hydrogen sulfide (H2S) releases.
§ 250.208
If I conduct ancillary activities, what notices must I provide?
At least 30 calendar days before you conduct any G&G exploration or development G&G activity (see § 250.207(a)), you must notify the Regional Supervisor in writing.
(a) When you prepare the notice, you must:
(1) Sign and date the notice;
(2) Provide the names of the vessel, its operator, and the person(s) in charge; the specific type(s) of operations you will conduct; and the instrumentation/techniques and vessel navigation system you will use;
(3) Provide expected start and completion dates and the location of the activity; and
(4) Describe the potential adverse environmental effects of the proposed activity and any mitigation to eliminate or minimize these effects on the marine, coastal, and human environment.
(b) The Regional Supervisor may require you to:
(1) Give written notice to MMS at least 15 calendar days before you conduct any other ancillary activity (see § 250.207(b) and (c)) in addition to those listed in § 250.207(a); and
(2) Notify other users of the OCS before you conduct any ancillary activity.
§ 250.209
What is the MMS review process for the notice?
The Regional Supervisor will review any notice required under § 250.208(a) and (b)(1) to ensure that your ancillary activity complies with the performance standards listed in § 250.202(a), (b), (d), and (e). The Regional Supervisor may notify you that your ancillary activity does not comply with those standards. In such a case, the Regional Supervisor will require you to submit an EP, DPP, or DOCD and you may not start your ancillary activity until the Regional Supervisor approves the EP, DPP, or DOCD.
§ 250.210
If I conduct ancillary activities, what reporting and data/information retention requirements must I satisfy?
(a) Reporting. The Regional Supervisor may require you to prepare and submit reports that summarize and analyze data or information obtained or derived from your ancillary activities. When applicable, MMS will protect and disclose the data and information in these reports in accordance with § 250.197(b).
(b) Data and information retention. You must retain copies of all original data and information, including navigation data, obtained or derived from your G&G explorations and development G&G activities (see § 250.207(a)), including any such data and information you obtained from previous leaseholders or unit operators. You must submit such data and information to MMS for inspection and possible retention upon request at any time before lease or unit termination. When applicable, MMS will protect and disclose such submitted data and information in accordance with § 250.197(b).
[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 25200, May 4, 2007]

Contents of Exploration Plans (EP)
§ 250.211
What must the EP include?
Your EP must include the following:
(a) Description, objectives, and schedule. A description, discussion of the objectives, and tentative schedule (from start to completion) of the exploration activities that you propose to undertake. Examples of exploration activities include exploration drilling, well test flaring, installing a well protection structure, and temporary well abandonment.
(b) Location. A map showing the surface location and water depth of each proposed well and the locations of all associated drilling unit anchors.
(c) Drilling unit. A description of the drilling unit and associated equipment you will use to conduct your proposed exploration activities, including a brief description of its important safety and pollution prevention features, and a table indicating the type and the estimated maximum quantity of fuels, oil, and lubricants that will be stored on the facility (see third definition of “facility” under § 250.105).
(d) Service fee. You must include payment of the service fee listed in § 250.125.
[70 FR 51501, Aug. 30, 2005, as amended at 71 FR 40911, July 19, 2006]
§ 250.212
What information must accompany the EP?
The following information must accompany your EP:
(a) General information required by § 250.213;
(b) Geological and geophysical (G&G) information required by § 250.214;
(c) Hydrogen sulfide information required by § 250.215;
(d) Biological, physical, and socioeconomic information required by § 250.216;
(e) Solid and liquid wastes and discharges information and cooling water intake information required by § 250.217;
(f) Air emissions information required by § 250.218;
(g) Oil and hazardous substance spills information required by § 250.219;
(h) Alaska planning information required by § 250.220;
(i) Environmental monitoring information required by § 250.221;
(j) Lease stipulations information required by § 250.222;
(k) Mitigation measures information required by § 250.223;
(l) Support vessels and aircraft information required by § 250.224;
(m) Onshore support facilities information required by § 250.225;
(n) Coastal zone management information required by § 250.226;
(o) Environmental impact analysis information required by § 250.227; and
(p) Administrative information required by § 250.228.
§ 250.213
What general information must accompany the EP?
The following general information must accompany your EP:
(a) Applications and permits. A listing, including filing or approval status, of the Federal, State, and local application approvals or permits you must obtain to conduct your proposed exploration activities.
(b) Drilling fluids. A table showing the projected amount, discharge rate, and chemical constituents for each type (i.e., water-based, oil-based, synthetic-based) of drilling fluid you plan to use to drill your proposed exploration wells.
(c) Chemical products. A table showing the name and brief description, quantities to be stored, storage method, and rates of usage of the chemical products you will use to conduct your proposed exploration activities. List only those chemical products you will store or use in quantities greater than the amounts defined as Reportable Quantities in 40 CFR part 302, or amounts specified by the Regional Supervisor.
(d) New or unusual technology. A description and discussion of any new or unusual technology (see definition under § 250.200) you will use to carry out your proposed exploration activities. In the public information copies of your EP, you may exclude any proprietary information from this description. In that case, include a brief discussion of the general subject matter of the omitted information. If you will not use any new or unusual technology to carry out your proposed exploration activities, include a statement so indicating.
(e) Bonds, oil spill financial responsibility, and well control statements. Statements attesting that:
(1) The activities and facilities proposed in your EP are or will be covered by an appropriate bond under 30 CFR part 256, subpart I;
(2) You have demonstrated or will demonstrate oil spill financial responsibility for facilities proposed in your EP according to 30 CFR part 253; and
(3) You have or will have the financial capability to drill a relief well and conduct other emergency well control operations.
(f) Suspensions of operations. A brief discussion of any suspensions of operations that you anticipate may be necessary in the course of conducting your activities under the EP.
(g) Blowout scenario. A scenario for the potential blowout of the proposed well in your EP that you expect will have the highest volume of liquid hydrocarbons. Include the estimated flow rate, total volume, and maximum duration of the potential blowout. Also, discuss the potential for the well to bridge over, the likelihood for surface intervention to stop the blowout, the availability of a rig to drill a relief well, and rig package constraints. Estimate the time it would take to drill a relief well.
(h) Contact. The name, address (e-mail address, if available), and telephone number of the person with whom the Regional Supervisor and any affected State(s) can communicate about your EP.
§ 250.214
What geological and geophysical (G&G) information must accompany the EP?
The following G&G information must accompany your EP:
(a) Geological description. A geological description of the prospect(s).
(b) Structure contour maps. Current structure contour maps (depth-based, expressed in feet subsea) drawn on the top of each prospective hydrocarbon-bearing reservoir showing the locations of proposed wells.
(c) Two-dimensional (2-D) or three-dimensional (3-D) seismic lines. Copies of migrated and annotated 2-D or 3-D seismic lines (with depth scale) intersecting at or near your proposed well locations. You are not required to conduct both 2-D and 3-D seismic surveys if you choose to conduct only one type of survey. If you have conducted both types of surveys, the Regional Supervisor may instruct you to submit the results of both surveys. You must interpret and display this information. Because of its volume, provide this information as an enclosure to only one proprietary copy of your EP.
(d) Geological cross-sections. Interpreted geological cross-sections showing the location and depth of each proposed well.
(e) Shallow hazards report. A shallow hazards report based on information obtained from a high-resolution geophysical survey, or a reference to such report if you have already submitted it to the Regional Supervisor.
(f) Shallow hazards assessment. For each proposed well, an assessment of any seafloor and subsurface geological and manmade features and conditions that may adversely affect your proposed drilling operations.
(g) High-resolution seismic lines. A copy of the high-resolution survey line closest to each of your proposed well locations. Because of its volume, provide this information as an enclosure to only one proprietary copy of your EP. You are not required to provide this information if the surface location of your proposed well has been approved in a previously submitted EP, DPP, or DOCD.
(h) Stratigraphic column. A generalized biostratigraphic/lithostratigraphic column from the surface to the total depth of the prospect.
(i) Time-versus-depth chart. A seismic travel time-versus-depth chart based on the appropriate velocity analysis in the area of interpretation and specifying the geodetic datum.
(j) Geochemical information. A copy of any geochemical reports you used or generated.
(k) Future G&G activities. A brief description of the types of G&G explorations and development G&G activities you may conduct for lease or unit purposes after your EP is approved.
§ 250.215
What hydrogen sulfide (H2S) information must accompany the EP?
The following H2S information, as applicable, must accompany your EP:
(a) Concentration. The estimated concentration of any H2S you might encounter while you conduct your proposed exploration activities.
(b) Classification. Under § 250.490(c), a request that the Regional Supervisor classify the area of your proposed exploration activities as either H2S absent, H2S present, or H2S unknown. Provide sufficient information to justify your request.
(c) H 2 S Contingency Plan. If you ask the Regional Supervisor to classify the area of your proposed exploration activities as either H2S present or H2S unknown, an H2S Contingency Plan prepared under § 250.490(f), or a reference to an approved or submitted H2S Contingency Plan that covers the proposed exploration activities.
(d) Modeling report. If you modeled a potential H2S release when developing your EP, modeling report or the modeling results, or a reference to such report or results if you have already submitted it to the Regional Supervisor.
(1) The analysis in the modeling report must be specific to the particular site of your proposed exploration activities, and must consider any nearby human-occupied OCS facilities, shipping lanes, fishery areas, and other points where humans may be subject to potential exposure from an H2S release from your proposed exploration activities.
(2) If any H2S emissions are projected to affect an onshore location in concentrations greater than 10 parts per million, the modeling analysis must be consistent with the Environmental Protection Agency's (EPA) risk management plan methodologies outlined in 40 CFR part 68.
§ 250.216
What biological, physical, and socioeconomic information must accompany the EP?
If you obtain the following information in developing your EP, or if the Regional Supervisor requires you to obtain it, you must include a report, or the information obtained, or a reference to such a report or information if you have already submitted it to the Regional Supervisor, as accompanying information:
(a) Biological environment reports. Site-specific information on chemosynthetic communities, federally listed threatened or endangered species, marine mammals protected under the Marine Mammal Protection Act (MMPA), sensitive underwater features, marine sanctuaries, critical habitat designated under the Endangered Species Act (ESA), or other areas of biological concern.
(b) Physical environment reports. Site-specific meteorological, physical oceanographic, geotechnical reports, or archaeological reports (if required under § 250.194).
(c) Socioeconomic study reports. Socioeconomic information regarding your proposed exploration activities.
[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 18584, Apr. 13, 2007]
§ 250.217
What solid and liquid wastes and discharges information and cooling water intake information must accompany the EP?
The following solid and liquid wastes and discharges information and cooling water intake information must accompany your EP:
(a) Projected wastes. A table providing the name, brief description, projected quantity, and composition of solid and liquid wastes (such as spent drilling fluids, drill cuttings, trash, sanitary and domestic wastes, and chemical product wastes) likely to be generated by your proposed exploration activities. Describe:
(1) The methods you used for determining this information; and
(2) Your plans for treating, storing, and downhole disposal of these wastes at your drilling location(s).
(b) Projected ocean discharges. If any of your solid and liquid wastes will be discharged overboard, or are planned discharges from manmade islands:
(1) A table showing the name, projected amount, and rate of discharge for each waste type; and
(2) A description of the discharge method (such as shunting through a downpipe, etc.) you will use.
(c) National Pollutant Discharge Elimination System (NPDES) permit. (1) A discussion of how you will comply with the provisions of the applicable general NPDES permit that covers your proposed exploration activities; or
(2) A copy of your application for an individual NPDES permit. Briefly describe the major discharges and methods you will use for compliance.
(d) Modeling report. The modeling report or the modeling results (if you modeled the discharges of your projected solid or liquid wastes when developing your EP), or a reference to such report or results if you have already submitted it to the Regional Supervisor.
(e) Projected cooling water intake. A table for each cooling water intake structure likely to be used by your proposed exploration activities that includes a brief description of the cooling water intake structure, daily water intake rate, water intake through screen velocity, percentage of water intake used for cooling water, mitigation measures for reducing impingement and entrainment of aquatic organisms, and biofouling prevention measures.
§ 250.218
What air emissions information must accompany the EP?
The following air emissions information, as applicable, must accompany your EP:
(a) Projected emissions. Tables showing the projected emissions of sulphur dioxide (SO2), particulate matter in the form of PM 10 and PM 2.5 when applicable, nitrogen oxides (NO X), carbon monoxide (CO), and volatile organic compounds (VOC) that will be generated by your proposed exploration activities.
(1) For each source on or associated with the drilling unit (including well test flaring and well protection structure installation), you must list:
(i) The projected peak hourly emissions;
(ii) The total annual emissions in tons per year;
(iii) Emissions over the duration of the proposed exploration activities;
(iv) The frequency and duration of emissions; and
(v) The total of all emissions listed in paragraphs (a)(1)(i) through (iv) of this section.
(2) You must provide the basis for all calculations, including engine size and rating, and applicable operational information.
(3) You must base the projected emissions on the maximum rated capacity of the equipment on the proposed drilling unit under its physical and operational design.
(4) If the specific drilling unit has not yet been determined, you must use the maximum emission estimates for the type of drilling unit you will use.
(b) Emission reduction measures. A description of any proposed emission reduction measures, including the affected source(s), the emission reduction control technologies or procedures, the quantity of reductions to be achieved, and any monitoring system you propose to use to measure emissions.
(c) Processes, equipment, fuels, and combustibles. A description of processes, processing equipment, combustion equipment, fuels, and storage units. You must include the characteristics and the frequency, duration, and maximum burn rate of any well test fluids to be burned.
(d) Distance to shore. Identification of the distance of your drilling unit from the mean high water mark (mean higher high water mark on the Pacific coast) of the adjacent State.
(e) Non-exempt drilling units. A description of how you will comply with § 250.303 when the projected emissions of SO2, PM, NO X, CO, or VOC, that will be generated by your proposed exploration activities, are greater than the respective emission exemption amounts “E” calculated using the formulas in § 250.303(d). When MMS requires air quality modeling, you must use the guidelines in Appendix W of 40 CFR part 51 with a model approved by the Director. Submit the best available meteorological information and data consistent with the model(s) used.
(f) Modeling report. A modeling report or the modeling results (if § 250.303 requires you to use an approved air quality model to model projected air emissions in developing your EP), or a reference to such a report or results if you have already submitted it to the Regional Supervisor.
§ 250.219
What oil and hazardous substance spills information must accompany the EP?
The following information regarding potential spills of oil (see definition under 30 CFR 254.6) and hazardous substances (see definition under 40 CFR part 116) as applicable, must accompany your EP:
(a) Oil spill response planning. The material required under paragraph (a)(1) or (a)(2) of this section:
(1) An Oil Spill Response Plan (OSRP) for the facilities you will use to conduct your exploration activities prepared according to the requirements of 30 CFR part 254, subpart B; or
(2) Reference to your approved regional OSRP (see 30 CFR 254.3) to include:
(i) A discussion of your regional OSRP;
(ii) The location of your primary oil spill equipment base and staging area;
(iii) The name(s) of your oil spill removal organization(s) for both equipment and personnel;
(iv) The calculated volume of your worst case discharge scenario (see 30 CFR 254.26(a)), and a comparison of the appropriate worst case discharge scenario in your approved regional OSRP with the worst case discharge scenario that could result from your proposed exploration activities; and
(v) A description of the worst case discharge scenario that could result from your proposed exploration activities (see 30 CFR 254.26(b), (c), (d), and (e)).
(b) Modeling report. If you model a potential oil or hazardous substance spill in developing your EP, a modeling report or the modeling results, or a reference to such report or results if you have already submitted it to the Regional Supervisor.
§ 250.220
If I propose activities in the Alaska OCS Region, what planning information must accompany the EP?
If you propose exploration activities in the Alaska OCS Region, the following planning information must accompany your EP:
(a) Emergency plans. A description of your emergency plans to respond to a blowout, loss or disablement of a drilling unit, and loss of or damage to support craft.
(b) Critical operations and curtailment procedures. Critical operations and curtailment procedures for your exploration activities. The procedures must identify ice conditions, weather, and other constraints under which the exploration activities will either be curtailed or not proceed.
§ 250.221
What environmental monitoring information must accompany the EP?
The following environmental monitoring information, as applicable, must accompany your EP:
(a) Monitoring systems. A description of any existing and planned monitoring systems that are measuring, or will measure, environmental conditions or will provide project-specific data or information on the impacts of your exploration activities.
(b) Incidental takes. If there is reason to believe that protected species may be incidentally taken by planned exploration activities, you must describe how you will monitor for incidental take of:
(1) Threatened and endangered species listed under the ESA and
(2) Marine mammals, as appropriate, if you have not already received authorization for incidental take as may be necessary under the MMPA.
(c) Flower Garden Banks National Marine Sanctuary (FGBNMS). If you propose to conduct exploration activities within the protective zones of the FGBNMS, a description of your provisions for monitoring the impacts of an oil spill on the environmentally sensitive resources at the FGBNMS.
[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 18584, Apr. 13, 2007]
§ 250.222
What lease stipulations information must accompany the EP?
A description of the measures you took, or will take, to satisfy the conditions of lease stipulations related to your proposed exploration activities must accompany your EP.
§ 250.223
What mitigation measures information must accompany the EP?
(a) If you propose to use any measures beyond those required by the regulations in this part to minimize or mitigate environmental impacts from your proposed exploration activities, a description of the measures you will use must accompany your EP.
(b) If there is reason to believe that protected species may be incidentally taken by planned exploration activities, you must include mitigation measures designed to avoid or minimize the incidental take of:
(1) Threatened and endangered species listed under the ESA and
(2) Marine mammals, as appropriate, if you have not already received authorization for incidental take as may be necessary under the MMPA.
[72 FR 18585, Apr. 13, 2007]
§ 250.224
What information on support vessels, offshore vehicles, and aircraft you will use must accompany the EP?
The following information on the support vessels, offshore vehicles, and aircraft you will use must accompany your EP:
(a) General. A description of the crew boats, supply boats, anchor handling vessels, tug boats, barges, ice management vessels, other vessels, offshore vehicles, and aircraft you will use to support your exploration activities. The description of vessels and offshore vehicles must estimate the storage capacity of their fuel tanks and the frequency of their visits to your drilling unit.
(b) Air emissions. A table showing the source, composition, frequency, and duration of the air emissions likely to be generated by the support vessels, offshore vehicles, and aircraft you will use that will operate within 25 miles of your drilling unit.
(c) Drilling fluids and chemical products transportation. A description of the transportation method and quantities of drilling fluids and chemical products (see § 250.213(b) and (c)) you will transport from the onshore support facilities you will use to your drilling unit.
(d) Solid and liquid wastes transportation. A description of the transportation method and a brief description of the composition, quantities, and destination(s) of solid and liquid wastes (see § 250.217(a)) you will transport from your drilling unit.
(e) Vicinity map. A map showing the location of your proposed exploration activities relative to the shoreline. The map must depict the primary route(s) the support vessels and aircraft will use when traveling between the onshore support facilities you will use and your drilling unit.
§ 250.225
What information on the onshore support facilities you will use must accompany the EP?
The following information on the onshore support facilities you will use must accompany your EP:
(a) General. A description of the onshore facilities you will use to provide supply and service support for your proposed exploration activities (e.g., service bases and mud company docks).
(1) Indicate whether the onshore support facilities are existing, to be constructed, or to be expanded.
(2) If the onshore support facilities are, or will be, located in areas not adjacent to the Western GOM, provide a timetable for acquiring lands (including rights-of-way and easements) and constructing or expanding the facilities. Describe any State or Federal permits or approvals (dredging, filling, etc.) that would be required for constructing or expanding them.
(b) Air emissions. A description of the source, composition, frequency, and duration of the air emissions (attributable to your proposed exploration activities) likely to be generated by the onshore support facilities you will use.
(c) Unusual solid and liquid wastes. A description of the quantity, composition, and method of disposal of any unusual solid and liquid wastes (attributable to your proposed exploration activities) likely to be generated by the onshore support facilities you will use. Unusual wastes are those wastes not specifically addressed in the relevant National Pollution Discharge Elimination System (NPDES) permit.
(d) Waste disposal. A description of the onshore facilities you will use to store and dispose of solid and liquid wastes generated by your proposed exploration activities (see § 250.217) and the types and quantities of such wastes.
§ 250.226
What Coastal Zone Management Act (CZMA) information must accompany the EP?
The following CZMA information must accompany your EP:
(a) Consistency certification. A copy of your consistency certification under section 307(c)(3)(B) of the CZMA (16 U.S.C. 1456(c)(3)(B)) and 15 CFR 930.76(d) stating that the proposed exploration activities described in detail in this EP comply with (name of State(s)) approved coastal management program(s) and will be conducted in a manner that is consistent with such program(s); and
(b) Other information. “Information” as required by 15 CFR 930.76(a) and 15 CFR 930.58(a)(2)) and “Analysis” as required by 15 CFR 930.58(a)(3).
§ 250.227
What environmental impact analysis (EIA) information must accompany the EP?
The following EIA information must accompany your EP:
(a) General requirements. Your EIA must:
(1) Assess the potential environmental impacts of your proposed exploration activities;
(2) Be project specific; and
(3) Be as detailed as necessary to assist the Regional Supervisor in complying with the National Environmental Policy Act (NEPA) of 1969 (42 U.S.C. 4321 et seq.) and other relevant Federal laws such as the ESA and the MMPA.
(b) Resources, conditions, and activities. Your EIA must describe those resources, conditions, and activities listed below that could be affected by your proposed exploration activities, or that could affect the construction and operation of facilities or structures, or the activities proposed in your EP.
(1) Meteorology, oceanography, geology, and shallow geological or manmade hazards;
(2) Air and water quality;
(3) Benthic communities, marine mammals, sea turtles, coastal and marine birds, fish and shellfish, and plant life;
(4) Threatened or endangered species and their critical habitat as defined by the Endangered Species Act of 1973;
(5) Sensitive biological resources or habitats such as essential fish habitat, refuges, preserves, special management areas identified in coastal management programs, sanctuaries, rookeries, and calving grounds;
(6) Archaeological resources;
(7) Socioeconomic resources including employment, existing offshore and coastal infrastructure (including major sources of supplies, services, energy, and water), land use, subsistence resources and harvest practices, recreation, recreational and commercial fishing (including typical fishing seasons, location, and type), minority and lower income groups, and coastal zone management programs;
(8) Coastal and marine uses such as military activities, shipping, and mineral exploration or development; and
(9) Other resources, conditions, and activities identified by the Regional Supervisor.
(c) Environmental impacts. Your EIA must:
(1) Analyze the potential direct and indirect impacts (including those from accidents, cooling water intake structures, and those identified in relevant ESA biological opinions such as, but not limited to, those from noise, vessel collisions, and marine trash and debris) that your proposed exploration activities will have on the identified resources, conditions, and activities;
(2) Analyze any potential cumulative impacts from other activities to those identified resources, conditions, and activities potentially impacted by your proposed exploration activities;
(3) Describe the type, severity, and duration of these potential impacts and their biological, physical, and other consequences and implications;
(4) Describe potential measures to minimize or mitigate these potential impacts; and
(5) Summarize the information you incorporate by reference.
(d) Consultation. Your EIA must include a list of agencies and persons with whom you consulted, or with whom you will be consulting, regarding potential impacts associated with your proposed exploration activities.
(e) References cited. Your EIA must include a list of the references that you cite in the EIA.
[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 18585, Apr. 13, 2007]
§ 250.228
What administrative information must accompany the EP?
The following administrative information must accompany your EP:
(a) Exempted information description (public information copies only). A description of the general subject matter of the proprietary information that is included in the proprietary copies of your EP or its accompanying information.
(b) Bibliography. (1) If you reference a previously submitted EP, DPP, DOCD, study report, survey report, or other material in your EP or its accompanying information, a list of the referenced material; and
(2) The location(s) where the Regional Supervisor can inspect the cited referenced material if you have not submitted it.

Review and Decision Process for the EP
§ 250.231
After receiving the EP, what will MMS do?
(a) Determine whether deemed submitted. Within 15 working days after receiving your proposed EP and its accompanying information, the Regional Supervisor will review your submission and deem your EP submitted if:
(1) The submitted information, including the information that must accompany the EP (refer to the list in § 250.212), fulfills requirements and is sufficiently accurate;
(2) You have provided all needed additional information (see § 250.201(b)); and
(3) You have provided the required number of copies (see § 250.206(a)).
(b) Identify problems and deficiencies. If the Regional Supervisor determines that you have not met one or more of the conditions in paragraph (a) of this section, the Regional Supervisor will notify you of the problem or deficiency within 15 working days after the Regional Supervisor receives your EP and its accompanying information. The Regional Supervisor will not deem your EP submitted until you have corrected all problems or deficiencies identified in the notice.
(c) Deemed submitted notification. The Regional Supervisor will notify you when the EP is deemed submitted.
§ 250.232
What actions will MMS take after the EP is deemed submitted?
(a) State and CZMA consistency reviews. Within 2 working days after deeming your EP submitted under § 250.231, the Regional Supervisor will use receipted mail or alternative method to send a public information copy of the EP and its accompanying information to the following:
(1) The Governor of each affected State. The Governor has 21 calendar days after receiving your deemed-submitted EP to submit comments. The Regional Supervisor will not consider comments received after the deadline.
(2) The CZMA agency of each affected State. The CZMA consistency review period under section 307(c)(3)(B)(ii) of the CZMA (16 U.S.C. 1456(c)(3)(B)(ii)) and 15 CFR 930.78 begins when the State's CZMA agency receives a copy of your deemed-submitted EP, consistency certification, and required necessary data and information (see 15 CFR 930.77(a)(1)).
(b) MMS compliance review. The Regional Supervisor will review the exploration activities described in your proposed EP to ensure that they conform to the performance standards in § 250.202.
(c) MMS environmental impact evaluation. The Regional Supervisor will evaluate the environmental impacts of the activities described in your proposed EP and prepare environmental documentation under the National Environmental Policy Act (NEPA) (42 U.S.C. 4321 et seq.) and the implementing regulations (40 CFR parts 1500 through 1508).
(d) Amendments. During the review of your proposed EP, the Regional Supervisor may require you, or you may elect, to change your EP. If you elect to amend your EP, the Regional Supervisor may determine that your EP, as amended, is subject to the requirements of § 250.231.
[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 25200, May 4, 2007]
§ 250.233
What decisions will MMS make on the EP and within what timeframe?
(a) Timeframe. The Regional Supervisor will take one of the actions shown in the table in paragraph (b) of this section within 30 calendar days after the Regional Supervisor deems your EP submitted under § 250.231, or receives the last amendment to your proposed EP, whichever occurs later.
(b) MMS decision. By the deadline in paragraph (a) of this section, the Regional Supervisor will take one of the following actions:
The regional supervisor will . . . | If . . . | And then . . .
(1) Approve your EP | It complies with all applicable requirements | The Regional Supervisor will notify you in writing of the decision and may require you to meet certain conditions, including those to provide monitoring information.
(2) Require you to modify your proposed EP | The Regional Supervisor finds that it is inconsistent with the lease, the Act, the regulations prescribed under the Act, or notify Federal laws | The Regional Supervisor will notify you in writing of the decision and describe the modifications you must make to your proposed EP to ensure it complies with all applicable requirements.
(3) Disapprove your EP | Your proposed activities would probably cause serious harm or damage to life (including fish or other aquatic life); property; any mineral (in areas leased or not leased); the national security or defense; or the marine, coastal, or human environment; and you cannot modify your proposed activities to avoid such condition(s) | (i) The Regional Supervisor will notify you in writing of the decision and describe the reason(s) for disapproving your EP. (ii) MMS may cancel your lease and compensate you under 43 U.S.C. 1334(a)(2)(C) and the implementing regulations in §§ 250.182, 250.184, and 250.185 and 30 CFR 256.77.
§ 250.234
How do I submit a modified EP or resubmit a disapproved EP, and when will MMS make a decision?
(a) Modified EP. If the Regional Supervisor requires you to modify your proposed EP under § 250.233(b)(2), you must submit the modification(s) to the Regional Supervisor in the same manner as for a new EP. You need submit only information related to the proposed modification(s).
(b) Resubmitted EP. If the Regional Supervisor disapproves your EP under § 250.233(b)(3), you may resubmit the disapproved EP if there is a change in the conditions that were the basis of its disapproval.
(c) MMS review and timeframe. The Regional Supervisor will use the performance standards in § 250.202 to either approve, require you to further modify, or disapprove your modified or resubmitted EP. The Regional Supervisor will make a decision within 30 calendar days after the Regional Supervisor deems your modified or resubmitted EP to be submitted, or receives the last amendment to your modified or resubmitted EP, whichever occurs later.
§ 250.235
If a State objects to the EP's coastal zone consistency certification, what can I do?
If an affected State objects to the coastal zone consistency certification accompanying your proposed EP within the timeframe prescribed in § 250.233(a) or § 250.234(c), you may do one of the following:
(a) Amend your EP. Amend your EP to accommodate the State's objection and submit the amendment to the Regional Supervisor for approval. The amendment needs to only address information related to the State's objection.
(b) Appeal. Appeal the State's objection to the Secretary of Commerce using the procedures in 15 CFR part 930, subpart H. The Secretary of Commerce will either:
(1) Grant your appeal by finding, under section 307(c)(3)(B)(iii) of the CZMA (16 U.S.C. 1456(c)(3)(B)(iii)), that each activity described in detail in your EP is consistent with the objectives of the CZMA, or is otherwise necessary in the interest of national security; or
(2) Deny your appeal, in which case you may amend your EP as described in paragraph (a) of this section.
(c) Withdraw your EP. Withdraw your EP if you decide not to conduct your proposed exploration activities.
[70 FR 51501, Aug. 30, 2005; 71 FR 12438, Mar. 10, 2006]

Contents of Development and Production Plans (DPP) and Development Operations Coordination Documents (DOCD)
§ 250.241
What must the DPP or DOCD include?
Your DPP or DOCD must include the following:
(a) Description, objectives, and schedule. A description, discussion of the objectives, and tentative schedule (from start to completion) of the development and production activities you propose to undertake. Examples of development and production activities include:
(1) Development drilling;
(2) Well test flaring;
(3) Installation of production platforms, satellite structures, subsea wellheads and manifolds, and lease term pipelines (see definition at § 250.105); and
(4) Installation of production facilities and conduct of production operations.
(b) Location. The location and water depth of each of your proposed wells and production facilities. Include a map showing the surface and bottom-hole location and water depth of each proposed well, the surface location of each production facility, and the locations of all associated drilling unit and construction barge anchors.
(c) Drilling unit. A description of the drilling unit and associated equipment you will use to conduct your proposed development drilling activities. Include a brief description of its important safety and pollution prevention features, and a table indicating the type and the estimated maximum quantity of fuels and oil that will be stored on the facility (see third definition of “facility” under § 250.105).
(d) Production facilities. A description of the production platforms, satellite structures, subsea wellheads and manifolds, lease term pipelines (see definition at § 250.105), production facilities, umbilicals, and other facilities you will use to conduct your proposed development and production activities. Include a brief description of their important safety and pollution prevention features, and a table indicating the type and the estimated maximum quantity of fuels and oil that will be stored on the facility (see third definition of “facility” under § 250.105).
(e) Service fee. You must include payment of the service fee listed in § 250.125.
[70 FR 51501, Aug. 30, 2005, as amended at 71 FR 40911, July 19, 2006]
§ 250.242
What information must accompany the DPP or DOCD?
The following information must accompany your DPP or DOCD.
(a) General information required by § 250.243;
(b) G&G information required by § 250.244;
(c) Hydrogen sulfide information required by § 250.245;
(d) Mineral resource conservation information required by § 250.246;
(e) Biological, physical, and socioeconomic information required by § 250.247;
(f) Solid and liquid wastes and discharges information and cooling water intake information required by § 250.248;
(g) Air emissions information required by § 250.249;
(h) Oil and hazardous substance spills information required by § 250.250;
(i) Alaska planning information required by § 250.251;
(j) Environmental monitoring information required by § 250.252;
(k) Lease stipulations information required by § 250.253;
(l) Mitigation measures information required by § 250.254;
(m) Decommissioning information required by § 250.255;
(n) Related facilities and operations information required by § 250.256;
(o) Support vessels and aircraft information required by § 250.257;
(p) Onshore support facilities information required by § 250.258;
(q) Sulphur operations information required by § 250.259;
(r) Coastal zone management information required by § 250.260;
(s) Environmental impact analysis information required by § 250.261; and
(t) Administrative information required by § 250.262.
§ 250.243
What general information must accompany the DPP or DOCD?
The following general information must accompany your DPP or DOCD:
(a) Applications and permits. A listing, including filing or approval status, of the Federal, State, and local application approvals or permits you must obtain to carry out your proposed development and production activities.
(b) Drilling fluids. A table showing the projected amount, discharge rate, and chemical constituents for each type (i.e., water based, oil based, synthetic based) of drilling fluid you plan to use to drill your proposed development wells.
(c) Production. The following production information:
(1) Estimates of the average and peak rates of production for each type of production and the life of the reservoir(s) you intend to produce; and
(2) The chemical and physical characteristics of the produced oil (see definition under 30 CFR 254.6) that you will handle or store at the facilities you will use to conduct your proposed development and production activities.
(d) Chemical products. A table showing the name and brief description, quantities to be stored, storage method, and rates of usage of the chemical products you will use to conduct your proposed development and production activities. You need list only those chemical products you will store or use in quantities greater than the amounts defined as Reportable Quantities in 40 CFR part 302, or amounts specified by the Regional Supervisor.
(e) New or unusual technology. A description and discussion of any new or unusual technology (see definition under § 250.200) you will use to carry out your proposed development and production activities. In the public information copies of your DPP or DOCD, you may exclude any proprietary information from this description. In that case, include a brief discussion of the general subject matter of the omitted information. If you will not use any new or unusual technology to carry out your proposed development and production activities, include a statement so indicating.
(f) Bonds, oil spill financial responsibility, and well control statements. Statements attesting that:
(1) The activities and facilities proposed in your DPP or DOCD are or will be covered by an appropriate bond under 30 CFR part 256, subpart I;
(2) You have demonstrated or will demonstrate oil spill financial responsibility for facilities proposed in your DPP or DOCD, according to 30 CFR Part 253; and
(3) You have or will have the financial capability to drill a relief well and conduct other emergency well control operations.
(g) Suspensions of production or operations. A brief discussion of any suspensions of production or suspensions of operations that you anticipate may be necessary in the course of conducting your activities under the DPP or DOCD.
(h) Blowout scenario. A scenario for a potential blowout of the proposed well in your DPP or DOCD that you expect will have the highest volume of liquid hydrocarbons. Include the estimated flow rate, total volume, and maximum duration of the potential blowout. Also, discuss the potential for the well to bridge over, the likelihood for surface intervention to stop the blowout, the availability of a rig to drill a relief well, and rig package constraints. Estimate the time it would take to drill a relief well.
(i) Contact. The name, mailing address, (e-mail address if available), and telephone number of the person with whom the Regional Supervisor and the affected State(s) can communicate about your DPP or DOCD.
§ 250.244
What geological and geophysical (G&G) information must accompany the DPP or DOCD?
The following G&G information must accompany your DPP or DOCD:
(a) Geological description. A geological description of the prospect(s).
(b) Structure contour maps. Current structure contour maps (depth-based, expressed in feet subsea) showing depths of expected productive formations and the locations of proposed wells.
(c) Two dimensional (2-D) or three-dimensional (3-D) seismic lines. Copies of migrated and annotated 2-D or 3-D seismic lines (with depth scale) intersecting at or near your proposed well locations. You are not required to conduct both 2-D and 3-D seismic surveys if you choose to conduct only one type of survey. If you have conducted both types of surveys, the Regional Supervisor may instruct you to submit the results of both surveys. You must interpret and display this information. Provide this information as an enclosure to only one proprietary copy of your DPP or DOCD.
(d) Geological cross-sections. Interpreted geological cross-sections showing the depths of expected productive formations.
(e) Shallow hazards report. A shallow hazards report based on information obtained from a high-resolution geophysical survey, or a reference to such report if you have already submitted it to the Regional Supervisor.
(f) Shallow hazards assessment. For each proposed well, an assessment of any seafloor and subsurface geologic and manmade features and conditions that may adversely affect your proposed drilling operations.
(g) High resolution seismic lines. A copy of the high-resolution survey line closest to each of your proposed well locations. Because of its volume, provide this information as an enclosure to only one proprietary copy of your DPP or DOCD. You are not required to provide this information if the surface location of your proposed well has been approved in a previously submitted EP, DPP, or DOCD.
(h) Stratigraphic column. A generalized biostratigraphic/lithostratigraphic column from the surface to the total depth of each proposed well.
(i) Time-versus-depth chart. A seismic travel time-versus-depth chart based on the appropriate velocity analysis in the area of interpretation and specifying the geodetic datum.
(j) Geochemical information. A copy of any geochemical reports you used or generated.
(k) Future G&G activities. A brief description of the G&G explorations and development G&G activities that you may conduct for lease or unit purposes after your DPP or DOCD is approved.
§ 250.245
What hydrogen sulfide (H2S) information must accompany the DPP or DOCD?
The following H2S information, as applicable, must accompany your DPP or DOCD:
(a) Concentration. The estimated concentration of any H2S you might encounter or handle while you conduct your proposed development and production activities.
(b) Classification. Under § 250.490(c), a request that the Regional Supervisor classify the area of your proposed development and production activities as either H2S absent, H2S present, or H2S unknown. Provide sufficient information to justify your request.
(c) H 2S Contingency Plan. If you request that the Regional Supervisor classify the area of your proposed development and production activities as either H2S present or H2S unknown, an H2S Contingency Plan prepared under § 250.490(f), or a reference to an approved or submitted H2S Contingency Plan that covers the proposed development and production activities.
(d) Modeling report. (1) If you have determined or estimated that the concentration of any H2S you may encounter or handle while you conduct your development and production activities will be greater than 500 parts per million (ppm), you must:
(i) Model a potential worst case H2S release from the facilities you will use to conduct your proposed development and production activities; and
(ii) Include a modeling report or modeling results, or a reference to such report or results if you have already submitted it to the Regional Supervisor.
(2) The analysis in the modeling report must be specific to the particular site of your development and production activities, and must consider any nearby human-occupied OCS facilities, shipping lanes, fishery areas, and other points where humans may be subject to potential exposure from an H2S release from your proposed activities.
(3) If any H2S emissions are projected to affect an onshore location in concentrations greater than 10 ppm, the modeling analysis must be consistent with the EPA's risk management plan methodologies outlined in 40 CFR part 68.
§ 250.246
What mineral resource conservation information must accompany the DPP or DOCD?
The following mineral resource conservation information, as applicable, must accompany your DPP or DOCD:
(a) Technology and reservoir engineering practices and procedures. A description of the technology and reservoir engineering practices and procedures you will use to increase the ultimate recovery of oil and gas (e.g., secondary, tertiary, or other enhanced recovery practices). If you will not use enhanced recovery practices initially, provide an explanation of the methods you considered and the reasons why you are not using them.
(b) Technology and recovery practices and procedures. A description of the technology and recovery practices and procedures you will use to ensure optimum recovery of oil and gas or sulphur.
(c) Reservoir development. A discussion of exploratory well results, other reservoir data, proposed well spacing, completion methods, and other relevant well plan information.
§ 250.247
What biological, physical, and socioeconomic information must accompany the DPP or DOCD?
If you obtain the following information in developing your DPP or DOCD, or if the Regional Supervisor requires you to obtain it, you must include a report, or the information obtained, or a reference to such a report or information if you have already submitted it to the Regional Supervisor, as accompanying information:
(a) Biological environment reports. Site-specific information on chemosynthetic communities, federally listed threatened or endangered species, marine mammals protected under the MMPA, sensitive underwater features, marine sanctuaries, critical habitat designated under the ESA, or other areas of biological concern.
(b) Physical environment reports. Site-specific meteorological, physical oceanographic, geotechnical reports, or archaeological reports (if required under § 250.194).
(c) Socioeconomic study reports. Socioeconomic information related to your proposed development and production activities.
[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 18585, Apr. 13, 2007]
§ 250.248
What solid and liquid wastes and discharges information and cooling water intake information must accompany the DPP or DOCD?
The following solid and liquid wastes and discharges information and cooling water intake information must accompany your DPP or DOCD:
(a) Projected wastes. A table providing the name, brief description, projected quantity, and composition of solid and liquid wastes (such as spent drilling fluids, drill cuttings, trash, sanitary and domestic wastes, produced waters, and chemical product wastes) likely to be generated by your proposed development and production activities. Describe:
(1) The methods you used for determining this information; and
(2) Your plans for treating, storing, and downhole disposal of these wastes at your facility location(s).
(b) Projected ocean discharges. If any of your solid and liquid wastes will be discharged overboard or are planned discharges from manmade islands:
(1) A table showing the name, projected amount, and rate of discharge for each waste type; and
(2) A description of the discharge method (such as shunting through a downpipe, adding to a produced water stream, etc.) you will use.
(c) National Pollutant Discharge Elimination System (NPDES) permit. (1) A discussion of how you will comply with the provisions of the applicable general NPDES permit that covers your proposed development and production activities; or
(2) A copy of your application for an individual NPDES permit. Briefly describe the major discharges and methods you will use for compliance.
(d) Modeling report. A modeling report or the modeling results (if you modeled the discharges of your projected solid or liquid wastes in developing your DPP or DOCD), or a reference to such report or results if you have already submitted it to the Regional Supervisor.
(e) Projected cooling water intake. A table for each cooling water intake structure likely to be used by your proposed development and production activities that includes a brief description of the cooling water intake structure, daily water intake rate, water intake through-screen velocity, percentage of water intake used for cooling water, mitigation measures for reducing impingement and entrainment of aquatic organisms, and biofouling prevention measures.
§ 250.249
What air emissions information must accompany the DPP or DOCD?
The following air emissions information, as applicable, must accompany your DPP or DOCD:
(a) Projected emissions. Tables showing the projected emissions of sulphur dioxide (SO2), particulate matter in the form of PM 10 and PM 2.5 when applicable, nitrogen oxides (NO X), carbon monoxide (CO), and volatile organic compounds (VOC) that will be generated by your proposed development and production activities.
(1) For each source on or associated with the facility you will use to conduct your proposed development and production activities, you must list:
(i) The projected peak hourly emissions;
(ii) The total annual emissions in tons per year;
(iii) Emissions over the duration of the proposed development and production activities;
(iv) The frequency and duration of emissions; and
(v) The total of all emissions listed in paragraph (a)(1)(i) through (iv) of this section.
(2) If your proposed production and development activities would result in an increase in the emissions of an air pollutant from your facility to an amount greater than the amount specified in your previously approved DPP or DOCD, you must show the revised emission rates for each source as well as the incremental change for each source.
(3) You must provide the basis for all calculations, including engine size and rating, and applicable operational information.
(4) You must base the projected emissions on the maximum rated capacity of the equipment and the maximum throughput of the facility you will use to conduct your proposed development and production activities under its physical and operational design.
(5) If the specific drilling unit has not yet been determined, you must use the maximum emission estimates for the type of drilling unit you will use.
(b) Emission reduction measures. A description of any proposed emission reduction measures, including the affected source(s), the emission reduction control technologies or procedures, the quantity of reductions to be achieved, and any monitoring system you propose to use to measure emissions.
(c) Processes, equipment, fuels, and combustibles. A description of processes, processing equipment, combustion equipment, fuels, and storage units. You must include the frequency, duration, and maximum burn rate of any flaring activity.
(d) Distance to shore. Identification of the distance of the site of your proposed development and production activities from the mean high water mark (mean higher high water mark on the Pacific coast) of the adjacent State.
(e) Non-exempt facilities. A description of how you will comply with § 250.303 when the projected emissions of SO2, PM, NO X, CO, or VOC that will be generated by your proposed development and production activities are greater than the respective emission exemption amounts “E” calculated using the formulas in § 250.303(d). When MMS requires air quality modeling, you must use the guidelines in Appendix W of 40 CFR part 51 with a model approved by the Director. Submit the best available meteorological information and data consistent with the model(s) used.
(f) Modeling report. A modeling report or the modeling results (if § 250.303 requires you to use an approved air quality model to model projected air emissions in developing your DPP or DOCD), or a reference to such report or results if you have already submitted it to the Regional Supervisor.
§ 250.250
What oil and hazardous substance spills information must accompany the DPP or DOCD?
The following information regarding potential spills of oil (see definition under 30 CFR 254.6) and hazardous substances (see definition under 40 CFR part 116), as applicable, must accompany your DPP or DOCD:
(a) Oil spill response planning. The material required under paragraph (a)(1) or (a)(2) of this section:
(1) An Oil Spill Response Plan (OSRP) for the facilities you will use to conduct your proposed development and production activities prepared according to the requirements of 30 CFR part 254, subpart B; or
(2) Reference to your approved regional OSRP (see 30 CFR 254.3) to include:
(i) A discussion of your regional OSRP;
(ii) The location of your primary oil spill equipment base and staging area;
(iii) The name(s) of your oil spill removal organization(s) for both equipment and personnel;
(iv) The calculated volume of your worst case discharge scenario (see 30 CFR 254.26(a)), and a comparison of the appropriate worst case discharge scenario in your approved regional OSRP with the worst case discharge scenario that could result from your proposed development and production activities; and
(v) A description of the worst case oil spill scenario that could result from your proposed development and production activities (see 30 CFR 254.26(b), (c), (d), and (e)).
(b) Modeling report. If you model a potential oil or hazardous substance spill in developing your DPP or DOCD, a modeling report or the modeling results, or a reference to such report or results if you have already submitted it to the Regional Supervisor.
§ 250.251
If I propose activities in the Alaska OCS Region, what planning information must accompany the DPP?
If you propose development and production activities in the Alaska OCS Region, the following planning information must accompany your DPP:
(a) Emergency plans. A description of your emergency plans to respond to a blowout, loss or disablement of a drilling unit, and loss of or damage to support craft; and
(b) Critical operations and curtailment procedures. Critical operations and curtailment procedures for your development and production activities. The procedures must identify ice conditions, weather, and other constraints under which the development and production activities will either be curtailed or not proceed.
§ 250.252
What environmental monitoring information must accompany the DPP or DOCD?
The following environmental monitoring information, as applicable, must accompany your DPP or DOCD:
(a) Monitoring systems. A description of any existing and planned monitoring systems that are measuring, or will measure, environmental conditions or will provide project-specific data or information on the impacts of your development and production activities.
(b) Incidental takes. If there is reason to believe that protected species may be incidentally taken by planned development and production activities, you must describe how you will monitor for incidental take of:
(1) Threatened and endangered species listed under the ESA and
(2) Marine mammals, as appropriate, if you have not already received authorization for incidental take of marine mammals as may be necessary under the MMPA.
(c) Flower Garden Banks National Marine Sanctuary (FGBNMS). If you propose to conduct development and production activities within the protective zones of the FGBNMS, a description of your provisions for monitoring the impacts of an oil spill on the environmentally sensitive resources of the FGBNMS.
[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 18585, Apr. 13, 2007]
§ 250.253
What lease stipulations information must accompany the DPP or DOCD?
A description of the measures you took, or will take, to satisfy the conditions of lease stipulations related to your proposed development and production activities must accompany your DPP or DOCD.
§ 250.254
What mitigation measures information must accompany the DPP or DOCD?
(a) If you propose to use any measures beyond those required by the regulations in this part to minimize or mitigate environmental impacts from your proposed development and production activities, a description of the measures you will use must accompany your DPP or DOCD.
(b) If there is reason to believe that protected species may be incidentally taken by planned development and production activities, you must include mitigation measures designed to avoid or minimize that incidental take of:
(1) Threatened and endangered species listed under the ESA and
(2) Marine mammals, as appropriate, if you have not already received authorization for incidental take as may be necessary under the MMPA.
[72 FR 18585, Apr. 13, 2007]
§ 250.255
What decommissioning information must accompany the DPP or DOCD?
A brief description of how you intend to decommission your wells, platforms, pipelines, and other facilities, and clear your site(s) must accompany your DPP or DOCD.
§ 250.256
What related facilities and operations information must accompany the DPP or DOCD?
The following information regarding facilities and operations directly related to your proposed development and production activities must accompany your DPP or DOCD.
(a) OCS facilities and operations. A description and location of any of the following that directly relate to your proposed development and production activities:
(1) Drilling units;
(2) Production platforms;
(3) Right-of-way pipelines (including those that transport chemical products and produced water); and
(4) Other facilities and operations located on the OCS (regardless of ownership).
(b) Transportation system. A discussion of the transportation system that you will use to transport your production to shore, including:
(1) Routes of any new pipelines;
(2) Information concerning barges and shuttle tankers, including the storage capacity of the transport vessel(s), and the number of transfers that will take place per year;
(3) Information concerning any intermediate storage or processing facilities;
(4) An estimate of the quantities of oil, gas, or sulphur to be transported from your production facilities; and
(5) A description and location of the primary onshore terminal.
§ 250.257
What information on the support vessels, offshore vehicles, and aircraft you will use must accompany the DPP or DOCD?
The following information on the support vessels, offshore vehicles, and aircraft you will use must accompany your DPP or DOCD:
(a) General. A description of the crew boats, supply boats, anchor handling vessels, tug boats, barges, ice management vessels, other vessels, offshore vehicles, and aircraft you will use to support your development and production activities. The description of vessels and offshore vehicles must estimate the storage capacity of their fuel tanks and the frequency of their visits to the facilities you will use to conduct your proposed development and production activities.
(b) Air emissions. A table showing the source, composition, frequency, and duration of the air emissions likely to be generated by the support vessels, offshore vehicles, and aircraft you will use that will operate within 25 miles of the facilities you will use to conduct your proposed development and production activities.
(c) Drilling fluids and chemical products transportation. A description of the transportation method and quantities of drilling fluids and chemical products (see § 250.243(b) and (d)) you will transport from the onshore support facilities you will use to the facilities you will use to conduct your proposed development and production activities.
(d) Solid and liquid wastes transportation. A description of the transportation method and a brief description of the composition, quantities, and destination(s) of solid and liquid wastes (see § 250.248(a)) you will transport from the facilities you will use to conduct your proposed development and production activities.
(e) Vicinity map. A map showing the location of your proposed development and production activities relative to the shoreline. The map must depict the primary route(s) the support vessels and aircraft will use when traveling between the onshore support facilities you will use and the facilities you will use to conduct your proposed development and production activities.
§ 250.258
What information on the onshore support facilities you will use must accompany the DPP or DOCD?
The following information on the onshore support facilities you will use must accompany your DPP or DOCD:
(a) General. A description of the onshore facilities you will use to provide supply and service support for your proposed development and production activities (e.g., service bases and mud company docks).
(1) Indicate whether the onshore support facilities are existing, to be constructed, or to be expanded; and
(2) For DPPs only, provide a timetable for acquiring lands (including rights-of-way and easements) and constructing or expanding any of the onshore support facilities.
(b) Air emissions. A description of the source, composition, frequency, and duration of the air emissions (attributable to your proposed development and production activities) likely to be generated by the onshore support facilities you will use.
(c) Unusual solid and liquid wastes. A description of the quantity, composition, and method of disposal of any unusual solid and liquid wastes (attributable to your proposed development and production activities) likely to be generated by the onshore support facilities you will use. Unusual wastes are those wastes not specifically addressed in the relevant National Pollution Discharge Elimination System (NPDES) permit.
(d) Waste disposal. A description of the onshore facilities you will use to store and dispose of solid and liquid wastes generated by your proposed development and production activities (see § 250.248(a)) and the types and quantities of such wastes.
§ 250.259
What sulphur operations information must accompany the DPP or DOCD?
If you are proposing to conduct sulphur development and production activities, the following information must accompany your DPP or DOCD:
(a) Bleedwater. A discussion of the bleedwater that will be generated by your proposed sulphur activities, including the measures you will take to mitigate the potential toxic or thermal impacts on the environment caused by the discharge of bleedwater.
(b) Subsidence. An estimate of the degree of subsidence expected at various stages of your sulphur development and production activities, and a description of the measures you will take to mitigate the effects of subsidence on existing or potential oil and gas production, production platforms, and production facilities, and to protect the environment.
§ 250.260
What Coastal Zone Management Act (CZMA) information must accompany the DPP or DOCD?
The following CZMA information must accompany your DPP or DOCD:
(a) Consistency certification. A copy of your consistency certification under section 307(c)(3)(B) of the CZMA (16 U.S.C. 1456(c)(3)(B)) and 15 CFR 930.76(c) stating that the proposed development and production activities described in detail in this DPP or DOCD comply with (name of State(s)) approved coastal management program(s) and will be conducted in a manner that is consistent with such program(s); and
(b) Other information. “Information” as required by 15 CFR 930.76(a) and 15 CFR 930.58(a)(2)) and “Analysis” as required by 15 CFR 930.58(a)(3).
[70 FR 51501, Aug. 30, 2005, as amended at 73 FR 20171, Apr. 15, 2008]
§ 250.261
What environmental impact analysis (EIA) information must accompany the DPP or DOCD?
The following EIA information must accompany your DPP or DOCD:
(a) General requirements. Your EIA must:
(1) Assess the potential environmental impacts of your proposed development and production activities;
(2) Be project specific; and
(3) Be as detailed as necessary to assist the Regional Supervisor in complying with the NEPA of 1969 (42 U.S.C. 4321 et seq.) and other relevant Federal laws such as the ESA and the MMPA.
(b) Resources, conditions, and activities. Your EIA must describe those resources, conditions, and activities listed below that could be affected by your proposed development and production activities, or that could affect the construction and operation of facilities or structures or the activities proposed in your DPP or DOCD.
(1) Meteorology, oceanography, geology, and shallow geological or manmade hazards;
(2) Air and water quality;
(3) Benthic communities, marine mammals, sea turtles, coastal and marine birds, fish and shellfish, and plant life;
(4) Threatened or endangered species and their critical habitat;
(5) Sensitive biological resources or habitats such as essential fish habitat, refuges, preserves, special management areas identified in coastal management programs, sanctuaries, rookeries, and calving grounds;
(6) Archaeological resources;
(7) Socioeconomic resources (including the approximate number, timing, and duration of employment of persons engaged in onshore support and construction activities), population (including the approximate number of people and families added to local onshore areas), existing offshore and onshore infrastructure (including major sources of supplies, services, energy, and water), types of contractors or vendors that may place a demand on local goods and services, land use, subsistence resources and harvest practices, recreation, recreational and commercial fishing (including seasons, location, and type), minority and lower income groups, and CZMA programs;
(8) Coastal and marine uses such as military activities, shipping, and mineral exploration or development; and
(9) Other resources, conditions, and activities identified by the Regional Supervisor.
(c) Environmental impacts. Your EIA must:
(1) Analyze the potential direct and indirect impacts (including those from accidents, cooling water intake structures, and those identified in relevant ESA biological opinions such as, but not limited to, those from noise, vessel collisions, and marine trash and debris) that your proposed development and production activities will have on the identified resources, conditions, and activities;
(2) Describe the type, severity, and duration of these potential impacts and their biological, physical, and other consequences and implications;
(3) Describe potential measures to minimize or mitigate these potential impacts;
(4) Describe any alternatives to your proposed development and production activities that you considered while developing your DPP or DOCD, and compare the potential environmental impacts; and
(5) Summarize the information you incorporate by reference.
(d) Consultation. Your EIA must include a list of agencies and persons with whom you consulted, or with whom you will be consulting, regarding potential impacts associated with your proposed development and production activities.
(e) References cited. Your EIA must include a list of the references that you cite in the EIA.
[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 18585, Apr. 13, 2007]
§ 250.262
What administrative information must accompany the DPP or DOCD?
The following administrative information must accompany your DPP or DOCD:
(a) Exempted information description (public information copies only). A description of the general subject matter of the proprietary information that is included in the proprietary copies of your DPP or DOCD or its accompanying information.
(b) Bibliography. (1) If you reference a previously submitted EP, DPP, DOCD, study report, survey report, or other material in your DPP or DOCD or its accompanying information, a list of the referenced material; and
(2) The location(s) where the Regional Supervisor can inspect the cited referenced material if you have not submitted it.

Review and Decision Process for the DPP or DOCD
§ 250.266
After receiving the DPP or DOCD, what will MMS do?
(a) Determine whether deemed submitted. Within 25 working days after receiving your proposed DPP or DOCD and its accompanying information, the Regional Supervisor will deem your DPP or DOCD submitted if:
(1) The submitted information, including the information that must accompany the DPP or DOCD (refer to the list in § 250.242), fulfills requirements and is sufficiently accurate;
(2) You have provided all needed additional information (see § 250.201(b)); and
(3) You have provided the required number of copies (see § 250.206(a)).
(b) Identify problems and deficiencies. If the Regional Supervisor determines that you have not met one or more of the conditions in paragraph (a) of this section, the Regional Supervisor will notify you of the problem or deficiency within 25 working days after the Regional Supervisor receives your DPP or DOCD and its accompanying information. The Regional Supervisor will not deem your DPP or DOCD submitted until you have corrected all problems or deficiencies identified in the notice.
(c) Deemed submitted notification. The Regional Supervisor will notify you when your DPP or DOCD is deemed submitted.
§ 250.267
What actions will MMS take after the DPP or DOCD is deemed submitted?
(a) State, local government, CZMA consistency, and other reviews. Within 2 working days after the Regional Supervisor deems your DPP or DOCD submitted under § 250.266, the Regional Supervisor will use receipted mail or alternative method to send a public information copy of the DPP or DOCD and its accompanying information to the following:
(1) The Governor of each affected State. The Governor has 60 calendar days after receiving your deemed-submitted DPP or DOCD to submit comments and recommendations. The Regional Supervisor will not consider comments and recommendations received after the deadline.
(2) The executive of any affected local government who requests a copy. The executive of any affected local government has 60 calendar days after receipt of your deemed-submitted DPP or DOCD to submit comments and recommendations. The Regional Supervisor will not consider comments and recommendations received after the deadline. The executive of any affected local government must forward all comments and recommendations to the respective Governor before submitting them to the Regional Supervisor.
(3) The CZMA agency of each affected State. The CZMA consistency review period under section 307(c)(3)(B)(ii) of the CZMA (16 U.S.C.1456(c)(3)(B)(ii)) and 15 CFR 930.78 begins when the States CZMA agency receives a copy of your deemed-submitted DPP or DOCD, consistency certification, and required necessary data/information (see 15 CFR 930.77(a)(1)).
(b) General public. Within 2 working days after the Regional Supervisor deems your DPP or DOCD submitted under § 250.266, the Regional Supervisor will make a public information copy of the DPP or DOCD and its accompanying information available for review to any appropriate interstate regional entity and the public at the appropriate MMS Regional Public Information Office. Any interested Federal agency or person may submit comments and recommendations to the Regional Supervisor. Comments and recommendations must be received by the Regional Supervisor within 60 calendar days after the DPP or DOCD including its accompanying information is made available.
(c) MMS compliance review. The Regional Supervisor will review the development and production activities in your proposed DPP or DOCD to ensure that they conform to the performance standards in § 250.202.
(d) Amendments. During the review of your proposed DPP or DOCD, the Regional Supervisor may require you, or you may elect, to change your DPP or DOCD. If you elect to amend your DPP or DOCD, the Regional Supervisor may determine that your DPP or DOCD, as amended, is subject to the requirements of § 250.266.
§ 250.268
How does MMS respond to recommendations?
(a) Governor. The Regional Supervisor will accept those recommendations from the Governor that provide a reasonable balance between the national interest and the well-being of the citizens of each affected State. The Regional Supervisor will explain in writing to the Governor the reasons for rejecting any of his or her recommendations.
(b) Local governments and the public. The Regional Supervisor may accept recommendations from the executive of any affected local government or the public.
(c) Availability. The Regional Supervisor will make all comments and recommendations available to the public upon request.
§ 250.269
How will MMS evaluate the environmental impacts of the DPP or DOCD?
The Regional Supervisor will evaluate the environmental impacts of the activities described in your proposed DPP or DOCD and prepare environmental documentation under the National Environmental Policy Act (NEPA) (42 U.S.C.4321 et seq.) and the implementing regulations (40 CFR parts 1500 through 1508).
(a) Environmental impact statement (EIS) declaration. At least once in each OCS planning area (other than the Western and Central GOM Planning Areas), the Director will declare that the approval of a proposed DPP is a major Federal action, and MMS will prepare an EIS.
(b) Leases or units in the vicinity. Before or immediately after the Director determines that preparation of an EIS is required, the Regional Supervisor may require lessees and operators of leases or units in the vicinity of the proposed development and production activities for which DPPs have not been approved to submit information about preliminary plans for their leases or units.
(c) Draft EIS. The Regional Supervisor will send copies of the draft EIS to the Governor of each affected State and to the executive of each affected local government who requests a copy. Additionally, when MMS prepares a DPP EIS, and the Federally-approved CZMA program for an affected State requires a DPP NEPA document for use in determining consistency, the Regional Supervisor will forward a copy of the draft EIS to the State's CZMA agency. The Regional Supervisor will also make copies of the draft EIS available to any appropriate Federal agency, interstate regional entity, and the public.
§ 250.270
What decisions will MMS make on the DPP or DOCD and within what timeframe?
(a) Timeframe. The Regional Supervisor will act on your deemed-submitted DPP or DOCD as follows:
(1) The Regional Supervisor will make a decision within 60 calendar days after the latest of the day that:
(i) The comment period provided in § 250.267(a)(1), (a)(2), and (b) closes;
(ii) The final EIS for a DPP is released or adopted; or
(iii) The last amendment to your proposed DOCD is received by the Regional Supervisor.
(2) Notwithstanding paragraph (a)(1) of this section, MMS will not approve your DPP or DOCD until either:
(i) All affected States with approved CZMA programs concur, or have been conclusively presumed to concur, with your DPP or DOCD consistency certification under section 307(c)(3)(B)(i) and (ii) of the CZMA (16 U.S.C. 1456(c)(3)(B)(i) and (ii)); or
(ii) The Secretary of Commerce has made a finding authorized by section 307(c)(3)(B)(iii) of the CZMA (16 U.S.C. 1456(c)(3)(B)(iii)) that each activity described in the DPP or DOCD is consistent with the objectives of the CZMA, or is otherwise necessary in the interest of national security.
(b) MMS decision. By the deadline in paragraph (a) of this section, the Regional Supervisor will take one of the following actions:
The regional supervisor will . . . | If . . . | And then . . .
(1) Approve your DPP or DOCD | It complies with all applicable requirements | The Regional Supervisor will notify you in writing of the decision and may require you to meet certain conditions, including those to provide monitoring information.
(2) Require you to modify your proposed DPP or DOCD | It fails to make adequate provisions for safety, environmental protection, or conservation of natural resources or otherwise does not comply with the lease, the Act, the regulations prescribed under the Act, or other Federal laws | The Regional Supervisor will notify you in writing of the decision and describe the modifications you must make to your proposed DPP or DOCD to ensure it complies with all applicable requirements.
(3) Disapprove your DPP or DOCD | Any of the reasons in § 250.271 apply | (i) The Regional Supervisor will notify you in writing of the decision and describe the reason(s) for disapproving your DPP or DOCD; and (ii) MMS may cancel your lease and compensate you under 43 U.S.C. 1351(h)(2)(C) and the implementing regulations in §§ 250.183, 250.184, and 250.185 and 30 CFR 256.77.
[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 18585, Apr. 13, 2007]
§ 250.271
For what reasons will MMS disapprove the DPP or DOCD?
The Regional Supervisor will disapprove your proposed DPP or DOCD if one of the four reasons in this section applies:
(a) Non-compliance. The Regional Supervisor determines that you have failed to demonstrate that you can comply with the requirements of the Outer Continental Shelf Lands Act, as amended (Act), implementing regulations, or other applicable Federal laws.
(b) No consistency concurrence. (1) An affected State has not yet issued a final decision on your coastal zone consistency certification (see 15 CFR 930.78(a)); or
(2) An affected State objects to your coastal zone consistency certification, and the Secretary of Commerce, under section 307(c)(3)(B)(iii) of the CZMA (16 U.S.C. 1456(c)(3)(B)(iii)), has not found that each activity described in the DPP or DOCD is consistent with the objectives of the CZMA or is otherwise necessary in the interest of national security.
(3) If the Regional Supervisor disapproved your DPP or DOCD for the sole reason that an affected State either has not yet issued a final decision on, or has objected to, your coastal zone consistency certification (see paragraphs (b)(1) and (2) in this section), the Regional Supervisor will approve your DPP or DOCD upon receipt of concurrence by the affected State, at the time concurrence of the affected State is conclusively presumed, or when the Secretary of Commerce makes a finding authorized by section 307(c)(3)(B)(iii) of the CZMA (16 U.S.C. 1456(c)(3)(B)(iii)) that each activity described in your DPP or DOCD is consistent with the objectives of the CZMA, or is otherwise necessary in the interest of national security. In that event, you do not need to resubmit your DPP or DOCD for approval under § 250.273(b).
(c) National security or defense conflicts. Your proposed activities would threaten national security or defense.
(d) Exceptional circumstances. The Regional Supervisor determines because of exceptional geological conditions, exceptional resource values in the marine or coastal environment, or other exceptional circumstances that all of the following apply:
(1) Implementing your DPP or DOCD would cause serious harm or damage to life (including fish and other aquatic life), property, any mineral deposits (in areas leased or not leased), the national security or defense, or the marine, coastal, or human environment;
(2) The threat of harm or damage will not disappear or decrease to an acceptable extent within a reasonable period of time; and
(3) The advantages of disapproving your DPP or DOCD outweigh the advantages of development and production.
§ 250.272
If a State objects to the DPP's or DOCD's coastal zone consistency certification, what can I do?
If an affected State objects to the coastal zone consistency certification accompanying your proposed or disapproved DPP or DOCD, you may do one of the following:
(a) Amend or resubmit your DPP or DOCD. Amend or resubmit your DPP or DOCD to accommodate the State's objection and submit the amendment or resubmittal to the Regional Supervisor for approval. The amendment or resubmittal needs to only address information related to the State's objections.
(b) Appeal. Appeal the State's objection to the Secretary of Commerce using the procedures in 15 CFR part 930, subpart H. The Secretary of Commerce will either:
(1) Grant your appeal by finding under section 307(c)(3)(B)(iii) of the CZMA (16 U.S.C.1456(c)(3)(B)(iii)) that each activity described in detail in your DPP or DOCD is consistent with the objectives of the CZMA, or is otherwise necessary in the interest of national security; or
(2) Deny your appeal, in which case you may amend or resubmit your DPP or DOCD, as described in paragraph (a) of this section.
(c) Withdraw your DPP or DOCD. Withdraw your DPP or DOCD if you decide not to conduct your proposed development and production activities.
§ 250.273
How do I submit a modified DPP or DOCD or resubmit a disapproved DPP or DOCD?
(a) Modified DPP or DOCD. If the Regional Supervisor requires you to modify your proposed DPP or DOCD under § 250.270(b)(2), you must submit the modification(s) to the Regional Supervisor in the same manner as for a new DPP or DOCD. You need submit only information related to the proposed modification(s).
(b) Resubmitted DPP or DOCD. If the Regional Supervisor disapproves your DPP or DOCD under § 250.270(b)(3), and except as provided in § 250.271(b)(3), you may resubmit the disapproved DPP or DOCD if there is a change in the conditions that were the basis of its disapproval.
(c) MMS review and timeframe. The Regional Supervisor will use the performance standards in § 250.202 to either approve, require you to further modify, or disapprove your modified or resubmitted DPP or DOCD. The Regional Supervisor will make a decision within 60 calendar days after the Regional Supervisor deems your modified or resubmitted DPP or DOCD to be submitted, or receives the last amendment to your modified or resubmitted DPP or DOCD, whichever occurs later.

Post-Approval Requirements for the EP, DPP, and DOCD
§ 250.280
How must I conduct activities under the approved EP, DPP, or DOCD?
(a) Compliance. You must conduct all of your lease and unit activities according to your approved EP, DPP, or DOCD and any approval conditions. If you fail to comply with your approved EP, DPP, or DOCD:
(1) You may be subject to MMS enforcement action, including civil penalties; and
(2) The lease(s) involved in your EP, DPP, or DOCD may be forfeited or cancelled under 43 U.S.C. 1334(c) or (d). If this happens, you will not be entitled to compensation under § 250.185(b) and 30 CFR 256.77.
(b) Emergencies. Nothing in this subpart or in your approved EP, DPP, or DOCD relieves you of, or limits your responsibility to take appropriate measures to meet emergency situations. In an emergency situation, the Regional Supervisor may approve or require departures from your approved EP, DPP, or DOCD.
§ 250.281
What must I do to conduct activities under the approved EP, DPP, or DOCD?
(a) Approvals and permits. Before you conduct activities under your approved EP, DPP, or DOCD you must obtain the following approvals and or permits, as applicable, from the District Manager or Regional Supervisor:
(1) Approval of applications for permits to drill (APDs) (see § 250.410);
(2) Approval of production safety systems (see § 250.800);
(3) Approval of new platforms and other structures (or major modifications to platforms and other structures) (see § 250.905);
(4) Approval of applications to install lease term pipelines (see § 250.1007); and
(5) Other permits, as required by applicable law.
(b) Conformance. The activities proposed in these applications and permits must conform to the activities described in detail in your approved EP, DPP, or DOCD.
(c) Separate State CZMA consistency review. APDs, and other applications for licenses, approvals, or permits to conduct activities under your approved EP, DPP, or DOCD including those identified in paragraph (a) of this section, are not subject to separate State CZMA consistency review.
(d) Approval restrictions for permits for activities conducted under EPs. The District Manager or Regional Supervisor will not approve any APDs or other applications for licenses, approvals, or permits under your approved EP until either:
(1) All affected States with approved coastal zone management programs concur, or are conclusively presumed to concur, with the coastal zone consistency certification accompanying your EP under section 307(c)(3)(B)(i) and (ii) of the CZMA (16 U.S.C. 1456(c)(3)(B)(i) and (ii)); or
(2) The Secretary of Commerce finds, under section 307(c)(3)(B)(iii) of the CZMA (16 U.S.C.1456(c)(3)(B)(iii)) that each activity covered by the EP is consistent with the objectives of the CZMA or is otherwise necessary in the interest of national security;
(3) If an affected State objects to the coastal zone consistency certification accompanying your approved EP after MMS has approved your EP, you may either:
(i) Revise your EP to accommodate the State's objection and submit the revision to the Regional Supervisor for approval; or
(ii) Appeal the State's objection to the Secretary of Commerce using the procedures in 15 CFR part 930 subpart H. The Secretary of Commerce will either:
(A) Grant your appeal by making the finding described in paragraph (d)(2) of this section; or
(B) Deny your appeal, in which case you may revise your EP as described in paragraph (d)(3)(i) of this section.
[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 25200, May 4, 2007]
§ 250.282
Do I have to conduct post-approval monitoring?
After approving your EP, DPP, or DOCD, the Regional Supervisor may direct you to conduct monitoring programs, including monitoring in accordance with the ESA and the MMPA. You must retain copies of all monitoring data obtained or derived from your monitoring programs and make them available to the MMS upon request. The Regional Supervisor may require you to:
(a) Monitoring plans. Submit monitoring plans for approval before you begin the work; and
(b) Monitoring reports. Prepare and submit reports that summarize and analyze data and information obtained or derived from your monitoring programs. The Regional Supervisor will specify requirements for preparing and submitting these reports.
[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 18585, Apr. 13, 2007]
§ 250.283
When must I revise or supplement the approved EP, DPP, or DOCD?
(a) Revised OCS plans. You must revise your approved EP, DPP, or DOCD when you propose to:
(1) Change the type of drilling rig (e.g., jack-up, platform rig, barge, submersible, semisubmersible, or drillship), production facility (e.g., caisson, fixed platform with piles, tension leg platform), or transportation mode (e.g., pipeline, barge);
(2) Change the surface location of a well or production platform by a distance more than that specified by the Regional Supervisor;
(3) Change the type of production or significantly increase the volume of production or storage capacity;
(4) Increase the emissions of an air pollutant to an amount that exceeds the amount specified in your approved EP, DPP, or DOCD;
(5) Significantly increase the amount of solid or liquid wastes to be handled or discharged;
(6) Request a new H2S area classification, or increase the concentration of H2S to a concentration greater than that specified by the Regional Supervisor;
(7) Change the location of your onshore support base either from one State to another or to a new base or a base requiring expansion; or
(8) Change any other activity specified by the Regional Supervisor.
(b) Supplemental OCS plans. You must supplement your approved EP, DPP, or DOCD when you propose to conduct activities on your lease(s) or unit that require approval of a license or permit which is not described in your approved EP, DPP, or DOCD. These types of changes are called supplemental OCS plans.
§ 250.284
How will MMS require revisions to the approved EP, DPP, or DOCD?
(a) Periodic review. The Regional Supervisor will periodically review the activities you conduct under your approved EP, DPP, or DOCD and may require you to submit updated information on your activities. The frequency and extent of this review will be based on the significance of any changes in available information and onshore or offshore conditions affecting, or affected by, the activities in your approved EP, DPP, or DOCD.
(b) Results of review. The Regional Supervisor may require you to revise your approved EP, DPP, or DOCD based on this review. In such cases, the Regional Supervisor will inform you of the reasons for the decision.
§ 250.285
How do I submit revised and supplemental EPs, DPPs, and DOCDs?
(a) Submittal. You must submit to the Regional Supervisor any revisions and supplements to approved EPs, DPPs, or DOCDs for approval, whether you initiate them or the Regional Supervisor orders them.
(b) Information. Revised and supplemental EPs, DPPs, and DOCDs need include only information related to or affected by the proposed changes, including information on changes in expected environmental impacts.
(c) Procedures. All supplemental EPs, DPPs, and DOCDs, and those revised EPs, DPPs, and DOCDs that the Regional Supervisor determines are likely to result in a significant change in the impacts previously identified and evaluated, are subject to all of the procedures under § 250.231 through § 250.235 for EPs and § 250.266 through § 250.273 for DPPs and DOCDs.
[70 FR 51501, Aug. 30, 2005, as amended at 72 FR 25201, May 4, 2007]

Deepwater Operations Plans (DWOP)
§ 250.286
What is a DWOP?
(a) A DWOP is a plan that provides sufficient information for MMS to review a deepwater development project, and any other project that uses non-conventional production or completion technology, from a total system approach. The DWOP does not replace, but supplements other submittals required by the regulations such as Exploration Plans, Development and Production Plans, and Development Operations Coordination Documents. MMS will use the information in your DWOP to determine whether the project will be developed in an acceptable manner, particularly with respect to operational safety and environmental protection issues involved with non-conventional production or completion technology.
(b) The DWOP process consists of two parts: a Conceptual Plan and the DWOP. Section 250.289 prescribes what the Conceptual Plan must contain, and § 250.292 prescribes what the DWOP must contain.
§ 250.287
For what development projects must I submit a DWOP?
You must submit a DWOP for each development project in which you will use non-conventional production or completion technology, regardless of water depth. If you are unsure whether MMS considers the technology of your project non-conventional, you must contact the Regional Supervisor for guidance.
§ 250.288
When and how must I submit the Conceptual Plan?
You must submit four copies, or one hard copy and one electronic version, of the Conceptual Plan to the Regional Director after you have decided on the general concept(s) for development and before you begin engineering design of the well safety control system or subsea production systems to be used after well completion.
§ 250.289
What must the Conceptual Plan contain?
In the Conceptual Plan, you must explain the general design basis and philosophy that you will use to develop the field. You must include the following information:
(a) An overview of the development concept(s);
(b) A well location plat;
(c) The system control type (i.e., direct hydraulic or electro-hydraulic); and
(d) The distance from each of the wells to the host platform.
§ 250.290
What operations require approval of the Conceptual Plan?
You may not complete any production well or install the subsea wellhead and well safety control system (often called the tree) before MMS has approved the Conceptual Plan.
§ 250.291
When and how must I submit the DWOP?
You must submit four copies, or one hard copy and one electronic version, of the DWOP to the Regional Director after you have substantially completed safety system design and before you begin to procure or fabricate the safety and operational systems (other than the tree), production platforms, pipelines, or other parts of the production system.
§ 250.292
What must the DWOP contain?
You must include the following information in your DWOP:
(a) A description and schematic of the typical wellbore, casing, and completion;
(b) Structural design, fabrication, and installation information for each surface system, including host facilities;
(c) Design, fabrication, and installation information on the mooring systems for each surface system;
(d) Information on any active stationkeeping system(s) involving thrusters or other means of propulsion used with a surface system;
(e) Information concerning the drilling and completion systems;
(f) Design and fabrication information for each riser system (e.g., drilling, workover, production, and injection);
(g) Pipeline information;
(h) Information about the design, fabrication, and operation of an offtake system for transferring produced hydrocarbons to a transport vessel;
(i) Information about subsea wells and associated systems that constitute all or part of a single project development covered by the DWOP;
(j) Flow schematics and Safety Analysis Function Evaluation (SAFE) charts (API RP 14C, subsection 4.3c, incorporated by reference in § 250.198) of the production system from the Surface Controlled Subsurface Safety Valve (SCSSV) downstream to the first item of separation equipment;
(k) A description of the surface/subsea safety system and emergency support systems to include a table that depicts what valves will close, at what times, and for what events or reasons;
(l) A general description of the operating procedures, including a table summarizing the curtailment of production and offloading based on operational considerations;
(m) A description of the facility installation and commissioning procedure;
(n) A discussion of any new technology that affects hydrocarbon recovery systems;
(o) A list of any alternate compliance procedures or departures for which you anticipate requesting approval; and
(p) Payment of the service fee listed in § 250.125.
[70 FR 51501, Aug. 30, 2005, as amended at 71 FR 40911, July 19, 2006]
§ 250.293
What operations require approval of the DWOP?
You may not begin production until MMS approves your DWOP.
§ 250.294
May I combine the Conceptual Plan and the DWOP?
If your development project meets the following criteria, you may submit a combined Conceptual Plan/DWOP on or before the deadline for submitting the Conceptual Plan.
(a) The project is located in water depths of less than 400 meters (1,312 feet); and
(b) The project is similar to projects involving non-conventional production or completion technology for which you have obtained approval previously.
§ 250.295
When must I revise my DWOP?
You must revise either the Conceptual Plan or your DWOP to reflect changes in your development project that materially alter the facilities, equipment, and systems described in your plan. You must submit the revision within 60 days after any material change to the information required for that part of your plan.

Conservation Information Documents (CID)
§ 250.296
When and how must I submit a CID or a revision to a CID?
(a) You must submit one original and two copies of a CID to the appropriate OCS Region at the same time you first submit your DOCD or DPP for any development of a lease or leases located in water depths greater than 400 meters (1,312 feet). You must also submit a CID for a Supplemental DOCD or DPP when requested by the Regional Supervisor. The submission of your CID must be accompanied by payment of the service fee listed in § 250.125.
(b) If you decide not to develop a reservoir you committed to develop in your CID, you must submit one original and two copies of a revision to the CID to the appropriate OCS Region. The revision to the CID must be submitted within 14 calendar days after making your decision not to develop the reservoir and before the reservoir is bypassed. The Regional Supervisor will approve or disapprove any such revision to the original CID. If the Regional Supervisor disapproves the revision, you must develop the reservoir as described in the original CID.
[70 FR 51501, Aug. 30, 2005, as amended at 71 FR 40911, July 19, 2006]
§ 250.297
What information must a CID contain?
(a) You must base the CID on wells drilled before your CID submittal, that define the extent of the reservoirs. You must notify MMS of any well that is drilled to total depth during the CID evaluation period and you may be required to update your CID.
(b) You must include all of the following information if available. Information must be provided for each hydrocarbon-bearing reservoir that is penetrated by a well that would meet the producibility requirements of § 250.115 or § 250.116:
(1) General discussion of the overall development of the reservoir;
(2) Summary spreadsheets of well log data and reservoir parameters (i.e., sand tops and bases, fluid contacts, net pay, porosity, water saturations, pressures, formation volume factor);
(3) Appropriate well logs, including digital well log (i.e., gamma ray, resistivity, neutron, density, sonic, caliper curves) curves in an acceptable digital format;
(4) Sidewall core/whole core and pressure-volume-temperature analysis;
(5) Structure maps, with the existing and proposed penetration points and subsea depths for all wells penetrating the reservoirs, fluid contacts (or the lowest or highest known levels in the absence of actual contacts), reservoir boundaries, and the scale of the map;
(6) Interpreted structural cross sections and corresponding interpreted seismic lines or block diagrams, as necessary, that include all current wellbores and planned wellbores on the leases or units to be developed, the reservoir boundaries, fluid contacts, depth scale, stratigraphic positions, and relative biostratigraphic ages;
(7) Isopach maps of each reservoir showing the net feet of pay for each well within the reservoir identified at the penetration point, along with the well name, labeled contours, and scale;
(8) Estimates of original oil and gas in-place and anticipated recoverable oil and gas reserves, all reservoir parameters, and risk factors and assumptions;
(9) Plat map at the same scale as the structure maps with existing and proposed well paths, as well as existing and proposed penetrations;
(10) Wellbore schematics indicating proposed perforations;
(11) Proposed wellbore utility chart showing all existing and proposed wells, with proposed completion intervals indicated for each borehole;
(12) Appropriate pressure data, specified by date, and whether estimated or measured;
(13) Description of reservoir development strategies;
(14) Description of the enhanced recovery practices you will use or, if you do not plan to use such practices, an explanation of the methods you considered and reasons you do not intend to use them;
(15) For each reservoir you do not intend to develop:
(i) A statement explaining the reason(s) you will not develop the reservoir, and
(ii) Economic justification, including costs, recoverable reserve estimate, production profiles, and pricing assumptions; and
(16) Any other appropriate data you used in performing your reservoir evaluations and preparing your reservoir development strategies.
§ 250.298
How long will MMS take to evaluate and make a decision on the CID?
(a) The Regional Supervisor will make a decision within 150 calendar days of receiving your CID. If MMS does not act within 150 calendar days, your CID is considered approved.
(b) MMS may suspend the 150-calendar-day evaluation period if there is missing, inconclusive, or inaccurate data, or when a well reaches total depth during the evaluation period. MMS may also suspend the evaluation period when a well penetrating a hydrocarbon-bearing structure reaches total depth during the evaluation period and the data from that well is needed for the CID. You will receive written notification from the Regional Supervisor describing the additional information that is needed, and the evaluation period will resume once MMS receives the requested information.
(c) The Regional Supervisor will approve or deny your CID request based on your commitment to develop economically producible reservoirs according to sound conservation, engineering, and economic practices.
§ 250.299
What operations require approval of the CID?
You may not begin production before you receive MMS approval of the CID.

Subpart C—Pollution Prevention and Control
§ 250.300
Pollution prevention.
(a) During the exploration, development, production, and transportation of oil and gas or sulphur, the lessee shall take measures to prevent unauthorized discharge of pollutants into the offshore waters. The lessee shall not create conditions that will pose unreasonable risk to public health, life, property, aquatic life, wildlife, recreation, navigation, commercial fishing, or other uses of the ocean.
(1) When pollution occurs as a result of operations conducted by or on behalf of the lessee and the pollution damages or threatens to damage life (including fish and other aquatic life), property, any mineral deposits (in areas leased or not leased), or the marine, coastal, or human environment, the control and removal of the pollution to the satisfaction of the District Manager shall be at the expense of the lessee. Immediate corrective action shall be taken in all cases where pollution has occurred. Corrective action shall be subject to modification when directed by the District Manager.
(2) If the lessee fails to control and remove the pollution, the Director, in cooperation with other appropriate Agencies of Federal, State, and local governments, or in cooperation with the lessee, or both, shall have the right to control and remove the pollution at the lessee's expense. Such action shall not relieve the lessee of any responsibility provided for by law.
(b)(1) The District Manager may restrict the rate of drilling fluid discharges or prescribe alternative discharge methods. The District Manager may also restrict the use of components which could cause unreasonable degradation to the marine environment. No petroleum-based substances, including diesel fuel, may be added to the drilling mud system without prior approval of the District Manager.
(2) Approval of the method of disposal of drill cuttings, sand, and other well solids shall be obtained from the District Manager.
(3) All hydrocarbon-handling equipment for testing and production such as separators, tanks, and treaters shall be designed, installed, and operated to prevent pollution. Maintenance or repairs which are necessary to prevent pollution of offshore waters shall be undertaken immediately.
(4) Curbs, gutters, drip pans, and drains shall be installed in deck areas in a manner necessary to collect all contaminants not authorized for discharge. Oil drainage shall be piped to a properly designed, operated, and maintained sump system which will automatically maintain the oil at a level sufficient to prevent discharge of oil into offshore waters. All gravity drains shall be equipped with a water trap or other means to prevent gas in the sump system from escaping through the drains. Sump piles shall not be used as processing devices to treat or skim liquids but may be used to collect treated-produced water, treated-produced sand, or liquids from drip pans and deck drains and as a final trap for hydrocarbon liquids in the event of equipment upsets. Improperly designed, operated, or maintained sump piles which do not prevent the discharge of oil into offshore waters shall be replaced or repaired.
(5) On artificial islands, all vessels containing hydrocarbons shall be placed inside an impervious berm or otherwise protected to contain spills. Drainage shall be directed away from the drilling rig to a sump. Drains and sumps shall be constructed to prevent seepage.
(6) Disposal of equipment, cables, chains, containers, or other materials into offshore waters is prohibited.
(c) Materials, equipment, tools, containers, and other items used in the Outer Continental Shelf (OCS) which are of such shape or configuration that they are likely to snag or damage fishing devices shall be handled and marked as follows:
(1) All loose material, small tools, and other small objects shall be kept in a suitable storage area or a marked container when not in use and in a marked container before transport over offshore waters;
(2) All cable, chain, or wire segments shall be recovered after use and securely stored until suitable disposal is accomplished;
(3) Skid-mounted equipment, portable containers, spools or reels, and drums shall be marked with the owner's name prior to use or transport over offshore waters; and
(4) All markings must clearly identify the owner and must be durable enough to resist the effects of the environmental conditions to which they may be exposed.
(d) Any of the items described in paragraph (c) of this section that are lost overboard shall be recorded on the facility's daily operations report, as appropriate, and reported to the District Manager.
[53 FR 10690, Apr. 1, 1988, as amended at 56 FR 32099, July 15, 1991. Redesignated at 63 FR 29479, May 29, 1998]
§ 250.301
Inspection of facilities.
(a) Drilling and production facilities shall be inspected daily or at intervals approved or prescribed by the District Manager to determine if pollution is occurring. Necessary maintenance or repairs shall be made immediately. Records of such inspections and repairs shall be maintained at the facility or at a nearby manned facility for 2 years.
[53 FR 10690, Apr. 1, 1988, as amended at 62 FR 13996, Mar. 25, 1997. Redesignated at 63 FR 29479, May 29, 1998]
§ 250.302
Definitions concerning air quality.
For purposes of §§ 250.303 and 250.304 of this part:
Air pollutant means any combination of agents for which the Environmental Protection Agency (EPA) has established, pursuant to section 109 of the Clean Air Act, national primary or secondary ambient air quality standards.
Attainment area means, for any air pollutant, an area which is shown by monitored data or which is calculated by air quality modeling (or other methods determined by the Administrator of EPA to be reliable) not to exceed any primary or secondary ambient air quality standards established by EPA.
Best available control technology (BACT) means an emission limitation based on the maximum degree of reduction for each air pollutant subject to regulation, taking into account energy, environmental and economic impacts, and other costs. The BACT shall be verified on a case-by-case basis by the Regional Supervisor and may include reductions achieved through the application of processes, systems, and techniques for the control of each air pollutant.
Emission offsets means emission reductions obtained from facilities, either onshore or offshore, other than the facility or facilities covered by the proposed Exploration Plan or Development and Production Plan.
Existing facility is an OCS facility described in an Exploration Plan or a Development and Production Plan submitted or approved prior to June 2, 1980.
Facility means any installation or device permanently or temporarily attached to the seabed which is used for exploration, development, and production activities for oil, gas, or sulphur and which emits or has the potential to emit any air pollutant from one or more sources. All equipment directly associated with the installation or device shall be considered part of a single facility if the equipment is dependent on, or affects the processes of, the installation or device. During production, multiple installations or devices will be considered to be a single facility if the installations or devices are directly related to the production of oil, gas, or sulphur at a single site. Any vessel used to transfer production from an offshore facility shall be considered part of the facility while physically attached to it.
Nonattainment area means, for any air pollutant, an area which is shown by monitored data or which is calculated by air quality modeling (or other methods determined by the Administrator of EPA to be reliable) to exceed any primary or secondary ambient air quality standard established by EPA.
Projected emissions means emissions, either controlled or uncontrolled, from a source(s).
Source means an emission point. Several sources may be included within a single facility.
Temporary facility means activities associated with the construction of platforms offshore or with facilities related to exploration for or development of offshore oil and gas resources which are conducted in one location for less than 3 years.
Volatile organic compound (VOC) means any organic compound which is emitted to the atmosphere as a vapor. The unreactive compounds are exempt from the above definition.
[53 FR 10690, Apr. 1, 1988, as amended at 56 FR 32100, July 15, 1991. Redesignated and amended at 63 FR 29479, 29485, May 29, 1998]
§ 250.303
Facilities described in a new or revised Exploration Plan or Development and Production Plan.
(a) New plans. All Exploration Plans and Development and Production Plans shall include the information required to make the necessary findings under paragraphs (d) through (i) of this section, and the lessee shall comply with the requirements of this section as necessary.
(b) Applicability of § 250.303 to existing facilities. (1) The Regional Supervisor may review any Exploration Plan or Development and Production Plan to determine whether any facility described in the plan should be subject to review under this section and has the potential to significantly affect the air quality of an onshore area. To make these decisions, the Regional Supervisor shall consider the distance of the facility from shore, the size of the facility, the number of sources planned for the facility and their operational status, and the air quality status of the onshore area.
(2) For a facility identified by the Regional Supervisor in paragraph (b)(1) of this section, the Regional Supervisor shall require the lessee to refer to the information required in § 250.218 or § 250.249 of this part and to submit only that information required to make the necessary findings under paragraphs (d) through (i) of this section. The lessee shall submit this information within 120 days of the Regional Supervisor's determination or within a longer period of time at the discretion of the Regional Supervisor. The lessee shall comply with the requirements of this section as necessary.
(c) Revised facilities. All revised Exploration Plans and Development and Production Plans shall include the information required to make the necessary findings under paragraphs (d) through (i) of this section. The lessee shall comply with the requirements of this section as necessary.
(d) Exemption formulas. To determine whether a facility described in a new, modified, or revised Exploration Plan or Development and Production Plan is exempt from further air quality review, the lessee shall use the highest annual-total amount of emissions from the facility for each air pollutant calculated in § 250.249(a) or § 250.218(a) of this part and compare these emissions to the emission exemption amount “E” for each air pollutant calculated using the following formulas: E=3400D 2/3 for carbon monoxide (CO); and E=33.3D for total suspended particulates (TSP), sulphur dioxide (SO2), nitrogen oxides (NO X), and VOC (where E is the emission exemption amount expressed in tons per year, and D is the distance of the proposed facility from the closest onshore area of a State expressed in statute miles). If the amount of these projected emissions is less than or equal to the emission exemption amount “E” for the air pollutant, the facility is exempt from further air quality review required under paragraphs (e) through (i) of this section.
(e) Significance levels. For a facility not exempt under paragraph (d) of this section for air pollutants other than VOC, the lessee shall use an approved air quality model to determine whether the projected emissions of those air pollutants from the facility result in an onshore ambient air concentration above the following significance levels:
Significance Levels: Air pollutant concentrations (µg/m^3)
Air pollutant | Averaging time (hours) | Annual | 24 | 8 | 3 | 1
SO2 | 1 | 5 | | 25 |
TSP | 1 | 5 | | |
NO2 | 1 | | | |
CO | | | 500 | | 2,000
(f) Significance determinations. (1) The projected emissions of any air pollutant other than VOC from any facility which result in an onshore ambient air concentration above the significance level determined under paragraph (e) of this section for that air pollutant, shall be deemed to significantly affect the air quality of the onshore area for that air pollutant.
(2) The projected emissions of VOC from any facility which is not exempt under paragraph (d) of this section for that air pollutant shall be deemed to significantly affect the air quality of the onshore area for VOC.
(g) Controls required. (1) The projected emissions of any air pollutant other than VOC from any facility, except a temporary facility, which significantly affect the quality of a nonattainment area, shall be fully reduced. This shall be done through the application of BACT and, if additional reductions are necessary, through the application of additional emission controls or through the acquisition of offshore or onshore offsets.
(2) The projected emissions of any air pollutant other than VOC from any facility which significantly affect the air quality of an attainment or unclassifiable area shall be reduced through the application of BACT.
(i) Except for temporary facilities, the lessee also shall use an approved air quality model to determine whether the emissions of TSP or SO2 that remain after the application of BACT cause the following maximum allowable increases over the baseline concentrations established in 40 CFR 52.21 to be exceeded in the attainment or unclassifiable area:
Maximum allowable concentration increases (µg/m^3)
Air pollutant | Averaging times | Annual mean ^1 | 24-hour maximum | 3-hour maximum
Class I:
TSP | 5 | 10 |
SO2 | 2 | 5 | 25
Class II:
TSP | 19 | 37 |
SO2 | 20 | 91 | 512
Class III:
TSP | 37 | 75 |
SO2 | 40 | 182 | 700
^1 For TSP—geometric; For SO2—arithmetric.
No concentration of an air pollutant shall exceed the concentration permitted under the national secondary ambient air quality standard or the concentration permitted under the national primary air quality standard, whichever concentration is lowest for the air pollutant for the period of exposure. For any period other than the annual period, the applicable maximum allowable increase may be exceeded during one such period per year at any one onshore location.
(ii) If the maximum allowable increases are exceeded, the lessee shall apply whatever additional emission controls are necessary to reduce or offset the remaining emissions of TSP or SO2 so that concentrations in the onshore ambient air of an attainment or unclassifiable area do not exceed the maximum allowable increases.
(3)(i) The projected emissions of VOC from any facility, except a temporary facility, which significantly affect the onshore air quality of a nonattainment area shall be fully reduced. This shall be done through the application of BACT and, if additional reductions are necessary, through the application of additional emission controls or through the acquisition of offshore or onshore offsets.
(ii) The projected emissions of VOC from any facility which significantly affect the onshore air quality of an attainment area shall be reduced through the application of BACT.
(4)(i) If projected emissions from a facility significantly affect the onshore air quality of both a nonattainment and an attainment or unclassifiable area, the regulatory requirements applicable to projected emissions significantly affecting a nonattainment area shall apply.
(ii) If projected emissions from a facility significantly affect the onshore air quality of more than one class of attainment area, the lessee must reduce projected emissions to meet the maximum allowable increases specified for each class in paragraph (g)(2)(i) of this section.
(h) Controls required on temporary facilities. The lessee shall apply BACT to reduce projected emissions of any air pollutant from a temporary facility which significantly affect the air quality of an onshore area of a State.
(i) Emission offsets. When emission offsets are to be obtained, the lessee must demonstrate that the offsets are equivalent in nature and quantity to the projected emissions that must be reduced after the application of BACT; a binding commitment exists between the lessee and the owner or owners of the source or sources; the appropriate air quality control jurisdiction has been notified of the need to revise the State Implementation Plan to include the information regarding the offsets; and the required offsets come from sources which affect the air quality of the area significantly affected by the lessee's offshore operations.
(j) Review of facilities with emissions below the exemption amount. If, during the review of a new, modified, or revised Exploration Plan or Development and Production Plan, the Regional Supervisor determines or an affected State submits information to the Regional Supervisor which demonstrates, in the judgment of the Regional Supervisor, that projected emissions from an otherwise exempt facility will, either individually or in combination with other facilities in the area, significantly affect the air quality of an onshore area, then the Regional Supervisor shall require the lessee to submit additional information to determine whether emission control measures are necessary. The lessee shall be given the opportunity to present information to the Regional Supervisor which demonstrates that the exempt facility is not significantly affecting the air quality of an onshore area of the State.
(k) Emission monitoring requirements. The lessee shall monitor, in a manner approved or prescribed by the Regional Supervisor, emissions from the facility. The lessee shall submit this information monthly in a manner and form approved or prescribed by the Regional Supervisor.
(l) Collection of meteorological data. The Regional Supervisor may require the lessee to collect, for a period of time and in a manner approved or prescribed by the Regional Supervisor, and submit meteorological data from a facility.
[53 FR 10690, Apr. 1, 1988; 53 FR 19856, May 31, 1988; 53 FR 26067, July 11, 1988. Redesignated and amended at 63 FR 29479, 29485, May 29, 1998; 70 FR 51518, Aug. 30, 2005]
§ 250.304
Existing facilities.
(a) Process leading to review of an existing facility. (1) An affected State may request that the Regional Supervisor supply basic emission data from existing facilities when such data are needed for the updating of the State's emission inventory. In submitting the request, the State must demonstrate that similar offshore and onshore facilities in areas under the State's jurisdiction are also included in the emission inventory.
(2) The Regional Supervisor may require lessees of existing facilities to submit basic emission data to a State submitting a request under paragraph (a)(1) of this section.
(3) The State submitting a request under paragraph (a)(1) of this section may submit information from its emission inventory which indicates that emissions from existing facilities may be significantly affecting the air quality of the onshore area of the State. The lessee shall be given the opportunity to present information to the Regional Supervisor which demonstrates that the facility is not significantly affecting the air quality of the State.
(4) The Regional Supervisor shall evaluate the information submitted under paragraph (a)(3) of this section and shall determine, based on the basic emission data, available meteorological data, and the distance of the facility or facilities from the onshore area, whether any existing facility has the potential to significantly affect the air quality of the onshore area of the State.
(5) If the Regional Supervisor determines that no existing facility has the potential to significantly affect the air quality of the onshore area of the State submitting information under paragraph (a)(3) of this section, the Regional Supervisor shall notify the State of and explain the reasons for this finding.
(6) If the Regional Supervisor determines that an existing facility has the potential to significantly affect the air quality of an onshore area of the State submitting information under paragraph (a)(3) of this section, the Regional Supervisor shall require the lessee to refer to the information requirements under § 250.218 or 250.249 of this part and submit only that information required to make the necessary findings under paragraphs (b) through (e) of this section. The lessee shall submit this information within 120 days of the Regional Supervisor's determination or within a longer period of time at the discretion of the Regional Supervisor. The lessee shall comply with the requirements of this section as necessary.
(b) Exemption formulas. To determine whether an existing facility is exempt from further air quality review, the lessee shall use the highest annual total amount of emissions from the facility for each air pollutant calculated in § 250.218(a) or 250.249(a) of this part and compare these emissions to the emission exemption amount “E” for each air pollutant calculated using the following formulas: E=3400D 2/3 for CO; and E=33.3D for TSP, SO2, NO X, and VOC (where E is the emission exemption amount expressed in tons per year, and D is the distance of the facility from the closest onshore area of the State expressed in statute miles). If the amount of projected emissions is less than or equal to the emission exemption amount “E” for the air pollutant, the facility is exempt for that air pollutant from further air quality review required under paragraphs (c) through (e) of this section.
(c) Significance levels. For a facility not exempt under paragraph (b) of this section for air pollutants other than VOC, the lessee shall use an approved air quality model to determine whether projected emissions of those air pollutants from the facility result in an onshore ambient air concentration above the following significance levels:
Significance Levels: Air Pollutant Concentrations (µG/M^3)
Air pollutant | Averaging time (hours) | Annual | 24 | 8 | 3 | 1
SO2 | 1 | 5 | | 25 |
TSP | 1 | 5 | | |
NO2 | 1 | | | |
CO | | | 500 | | 2,000
(d) Significance determinations. (1) The projected emissions of any air pollutant other than VOC from any facility which result in an onshore ambient air concentration above the significance levels determined under paragraph (c) of this section for that air pollutant shall be deemed to significantly affect the air quality of the onshore area for that air pollutant.
(2) The projected emissions of VOC from any facility which is not exempt under paragraph (b) of this section for that air pollutant shall be deemed to significantly affect the air quality of the onshore area for VOC.
(e) Controls required. (1) The projected emissions of any air pollutant which significantly affect the air quality of an onshore area shall be reduced through the application of BACT.
(2) The lessee shall submit a compliance schedule for the application of BACT. If it is necessary to cease operations to allow for the installation of emission controls, the lessee may apply for a suspension of operations under the provisions of § 250.174 of this part.
(f) Review of facilities with emissions below the exemption amount. If, during the review of the information required under paragraph (a)(6) of this section, the Regional Supervisor determines or an affected State submits information to the Regional Supervisor which demonstrates, in the judgment of the Regional Supervisor, that projected emissions from an otherwise exempt facility will, either individually or in combination with other facilities in the area, significantly affect the air quality of an onshore area, then the Regional Supervisor shall require the lessee to submit additional information to determine whether control measures are necessary. The lessee shall be given the opportunity to present information to the Regional Supervisor which demonstrates that the exempt facility is not significantly affecting the air quality of an onshore area of the State.
(g) Emission monitoring requirements. The lessee shall monitor, in a manner approved or prescribed by the Regional Supervisor, emissions from the facility following the installation of emission controls. The lessee shall submit this information monthly in a manner and form approved or prescribed by the Regional Supervisor.
(h) Collection of meteorological data. The Regional Supervisor may require the lessee to collect, for a period of time and in a manner approved or prescribed by the Regional Supervisor, and submit meteorological data from a facility.
[53 FR 10690, Apr. 1, 1988; 53 FR 26067, July 11, 1988. Redesignated and amended at 63 FR 29479, 29485, May 29, 1998; 64 FR 72794, Dec. 28, 1999; 70 FR 51519, Aug. 30, 2005]

Subpart D—Oil and Gas Drilling Operations

General Requirements
§ 250.400
Who is subject to the requirements of this subpart?
The requirements of this subpart apply to lessees, operating rights owners, operators, and their contractors and subcontractors.
[68 FR 8423, Feb. 20, 2003]
§ 250.401
What must I do to keep wells under control?
You must take necessary precautions to keep wells under control at all times. You must:
(a) Use the best available and safest drilling technology to monitor and evaluate well conditions and to minimize the potential for the well to flow or kick;
(b) Have a person onsite during drilling operations who represents your interests and can fulfill your responsibilities;
(c) Ensure that the toolpusher, operator's representative, or a member of the drilling crew maintains continuous surveillance on the rig floor from the beginning of drilling operations until the well is completed or abandoned, unless you have secured the well with blowout preventers (BOPs), bridge plugs, cement plugs, or packers;
(d) Use personnel trained according to the provisions of subpart O; and
(e) Use and maintain equipment and materials necessary to ensure the safety and protection of personnel, equipment, natural resources, and the environment.
[68 FR 8423, Feb. 20, 2003]
§ 250.402
When and how must I secure a well?
Whenever you interrupt drilling operations, you must install a downhole safety device, such as a cement plug, bridge plug, or packer. You must install the device at an appropriate depth within a properly cemented casing string or liner.
(a) Among the events that may cause you to interrupt drilling operations are:
(1) Evacuation of the drilling crew;
(2) Inability to keep the drilling rig on location; or
(3) Repair to major drilling or well-control equipment.
(b) For floating drilling operations, the District Manager may approve the use of blind or blind-shear rams or pipe rams and an inside BOP if you don't have time to install a downhole safety device or if special circumstances occur.
[68 FR 8423, Feb. 20, 2003]
§ 250.403
What drilling unit movements must I report?
(a) You must report the movement of all drilling units on and off drilling locations to the District Manager. This includes both MODU and platform rigs. You must inform the District Manager 24 hours before:
(1) The arrival of an MODU on location;
(2) The movement of a platform rig to a platform;
(3) The movement of a platform rig to another slot;
(4) The movement of an MODU to another slot; and
(5) The departure of an MODU from the location.
(b) You must provide the District Manager with the rig name, lease number, well number, and expected time of arrival or departure.
(c) In the Gulf of Mexico OCS Region, you must report drilling unit movements on form MMS-144, Rig Movement Notification Report.
[68 FR 8423, Feb. 20, 2003]
§ 250.404
What are the requirements for the crown block?
You must have a crown block safety device that prevents the traveling block from striking the crown block. You must check the device for proper operation at least once per week and after each drill-line slipping operation and record the results of this operational check in the driller's report.
[68 FR 8423, Feb. 20, 2003]
§ 250.405
What are the safety requirements for diesel engines used on a drilling rig?
You must equip each diesel engine with an air take device to shut down the diesel engine in the event of a runaway.
(a) For a diesel engine that is not continuously manned, you must equip the engine with an automatic shutdown device;
(b) For a diesel engine that is continuously manned, you may equip the engine with either an automatic or remote manual air intake shutdown device;
(c) You do not have to equip a diesel engine with an air intake device if it meets one of the following criteria:
(1) Starts a larger engine;
(2) Powers a firewater pump;
(3) Powers an emergency generator;
(4) Powers a BOP accumulator system;
(5) Provides air supply to divers or confined entry personnel;
(6) Powers temporary equipment on a nonproducing platform;
(7) Powers an escape capsule; or
(8) Powers a portable single-cylinder rig washer.
[68 FR 8423, Feb. 20, 2003]
§ 250.406
What additional safety measures must I take when I conduct drilling operations on a platform that has producing wells or has other hydrocarbon flow?
You must take the following safety measures when you conduct drilling operations on a platform with producing wells or that has other hydrocarbon flow:
(a) You must install an emergency shutdown station near the driller's console;
(b) You must shut in all producible wells located in the affected wellbay below the surface and at the wellhead when:
(1) You move a drilling rig or related equipment on and off a platform. This includes rigging up and rigging down activities within 500 feet of the affected platform;
(2) You move or skid a drilling unit between wells on a platform;
(3) A mobile offshore drilling unit (MODU) moves within 500 feet of a platform. You may resume production once the MODU is in place, secured, and ready to begin drilling operations.
[68 FR 8423, Feb. 20, 2003]
§ 250.407
What tests must I conduct to determine reservoir characteristics?
You must determine the presence, quantity, quality, and reservoir characteristics of oil, gas, sulphur, and water in the formations penetrated by logging, formation sampling, or well testing.
[68 FR 8423, Feb. 20, 2003]
§ 250.408
May I use alternative procedures or equipment during drilling operations?
You may use alternative procedures or equipment during drilling operations after receiving approval from the District Manager. You must identify and discuss your proposed alternative procedures or equipment in your Application for Permit to Drill (APD) (Form MMS-123) (see § 250.414(h)). Procedures for obtaining approval are described in section 250.141 of this part.
[68 FR 8423, Feb. 20, 2003, as amended at 72 FR 25201, May 4, 2007]
§ 250.409
May I obtain departures from these drilling requirements?
The District Manager may approve departures from the drilling requirements specified in this subpart. You may apply for a departure from drilling requirements by writing to the District Manager. You should identify and discuss the departure you are requesting in your APD (see § 250.414(h)).
[68 FR 8423, Feb. 20, 2003]

Applying for a Permit To Drill
§ 250.410
How do I obtain approval to drill a well?
You must obtain written approval from the District Manager before you begin drilling any well or before you sidetrack, bypass, or deepen a well. To obtain approval, you must:
(a) Submit the information required by § 250.411 through 250.418;
(b) Include the well in your approved Exploration Plan (EP), Development and Production Plan (DPP), or Development Operations Coordination Document (DOCD);
(c) Meet the oil spill financial responsibility requirements for offshore facilities as required by 30 CFR part 253; and
(d) Submit the following to the District Manager:
(1) An original and two complete copies of Form MMS-123, Application for Permit to Drill (APD), and Form MMS-123S, Supplemental APD Information Sheet;
(2) A separate public information copy of forms MMS-123 and MMS-123S that meets the requirements of § 250.186; and
(3) Payment of the service fee listed in § 250.125.
[68 FR 8423, Feb. 20, 2003, as amended at 71 FR 40911, July 19, 2006; 72 FR 25201, May 4, 2007]
§ 250.411
What information must I submit with my application?
In addition to forms MMS-123 and MMS-123S, you must include the information described in the following table.
Information that you must include with an APD | Where to find a description
(a) Plat that shows locations of the proposed well | § 250.412
(b) Design criteria used for the proposed well | § 250.413
(c) Drilling prognosis | § 250.414
(d) Casing and cementing programs | § 250.415
(e) Diverter and BOP systems descriptions | § 250.416
(f) Requirements for using an MODU | § 250.417
(g) Additional information | § 250.418
[68 FR 8423, Feb. 20, 2003]
§ 250.412
What requirements must the location plat meet?
The location plat must:
(a) Have a scale of 1:24,000 (1 inch = 2,000 feet);
(b) Show the surface and subsurface locations of the proposed well and all the wells in the vicinity;
(c) Show the surface and subsurface locations of the proposed well in feet or meters from the block line;
(d) Contain the longitude and latitude coordinates, and either Universal Transverse Mercator grid-system coordinates or state plane coordinates in the Lambert or Transverse Mercator Projection system for the surface and subsurface locations of the proposed well; and
(e) State the units and geodetic datum (including whether the datum is North American Datum 27 or 83) for these coordinates. If the datum was converted, you must state the method used for this conversion, since the various methods may produce different values.
[68 FR 8423, Feb. 20, 2003]
§ 250.413
What must my description of well drilling design criteria address?
Your description of well drilling design criteria must address:
(a) Pore pressures;
(b) Formation fracture gradients, adjusted for water depth;
(c) Potential lost circulation zones;
(d) Drilling fluid weights;
(e) Casing setting depths;
(f) Maximum anticipated surface pressures. For this section, maximum anticipated surface pressures are the pressures that you reasonably expect to be exerted upon a casing string and its related wellhead equipment. In calculating maximum anticipated surface pressures, you must consider: drilling, completion, and producing conditions; drilling fluid densities to be used below various casing strings; fracture gradients of the exposed formations; casing setting depths; total well depth; formation fluid types; safety margins; and other pertinent conditions. You must include the calculations used to determine the pressures for the drilling and the completion phases, including the anticipated surface pressure used for designing the production string;
(g) A single plot containing estimated pore pressures, formation fracture gradients, proposed drilling fluid weights, and casing setting depths in true vertical measurements;
(h) A summary report of the shallow hazards site survey that describes the geological and manmade conditions if not previously submitted; and
(i) Permafrost zones, if applicable.
[68 FR 8423, Feb. 20, 2003]
§ 250.414
What must my drilling prognosis include?
Your drilling prognosis must include a brief description of the procedures you will follow in drilling the well. This prognosis includes but is not limited to the following:
(a) Projected plans for coring at specified depths;
(b) Projected plans for logging;
(c) Planned safe drilling margin between proposed drilling fluid weights and estimated pore pressures. This safe drilling margin may be shown on the plot required by § 250.413(g);
(d) Estimated depths to the top of significant marker formations;
(e) Estimated depths to significant porous and permeable zones containing fresh water, oil, gas, or abnormally pressured formation fluids;
(f) Estimated depths to major faults;
(g) Estimated depths of permafrost, if applicable;
(h) A list and description of all requests for using alternative procedures or departures from the requirements of this subpart in one place in the APD. You must explain how the alternative procedures afford an equal or greater degree of protection, safety, or performance, or why you need the departures; and
(i) Projected plans for well testing (refer to § 250.460 for safety requirements).
[68 FR 8423, Feb. 20, 2003]
§ 250.415
What must my casing and cementing programs include?
Your casing and cementing programs must include:
(a) Hole sizes and casing sizes, including: weights; grades; collapse, and burst values; types of connection; and setting depths (measured and true vertical depth (TVD));
(b) Casing design safety factors for tension, collapse, and burst with the assumptions made to arrive at these values;
(c) Type and amount of cement (in cubic feet) planned for each casing string; and
(d) In areas containing permafrost, setting depths for conductor and surface casing based on the anticipated depth of the permafrost. Your program must provide protection from thaw subsidence and freezeback effect, proper anchorage, and well control.
(e) A statement of how you evaluated the best practices included in API RP 65, Recommended Practice for Cementing Shallow Water Flow Zones in Deep Water Wells (incorporated by reference as specified in § 250.198), if you drill a well in water depths greater than 500 feet and are in either of the following two areas:
(1) An “area with an unknown shallow water flow potential” is a zone or geologic formation where neither the presence nor absence of potential for a shallow water flow has been confirmed.
(2) An “area known to contain a shallow water flow hazard” is a zone or geologic formation for which drilling has confirmed the presence of shallow water flow.
[68 FR 8423, Feb. 20, 2003, as amended at 72 FR 8903, Feb. 28, 2007]
§ 250.416
What must I include in the diverter and BOP descriptions?
You must include in the diverter and BOP descriptions:
(a) A description of the diverter system and its operating procedures;
(b) A schematic drawing of the diverter system (plan and elevation views) that shows:
(1) The size of the annular BOP installed in the diverter housing;
(2) Spool outlet internal diameter(s);
(3) Diverter-line lengths and diameters; burst strengths and radius of curvature at each turn; and
(4) Valve type, size, working pressure rating, and location;
(c) A description of the BOP system and system components, including pressure ratings of BOP equipment and proposed BOP test pressures;
(d) A schematic drawing of the BOP system that shows the inside diameter of the BOP stack, number and type of preventers, location of choke and kill lines, and associated valves; and
(e) Information that shows the blind-shear rams installed in the BOP stack (both surface and subsea stacks) are capable of shearing the drill pipe in the hole under maximum anticipated surface pressures.
[68 FR 8423, Feb. 20, 2003]
§ 250.417
What must I provide if I plan to use a mobile offshore drilling unit (MODU)?
If you plan to use a MODU, you must provide:
(a) Fitness requirements. You must provide information and data to demonstrate the drilling unit's capability to perform at the proposed drilling location. This information must include the maximum environmental and operational conditions that the unit is designed to withstand, including the minimum air gap necessary for both hurricane and non-hurricane seasons. If sufficient environmental information and data are not available at the time you submit your APD, the District Manager may approve your APD but require you to collect and report this information during operations. Under this circumstance, the District Manager has the right to revoke the approval of the APD if information collected during operations show that the drilling unit is not capable of performing at the proposed location.
(b) Foundation requirements. You must provide information to show that site-specific soil and oceanographic conditions are capable of supporting the proposed drilling unit. If you provided sufficient site-specific information in your EP, DPP, or DOCD, you may reference that information. The District Manager may require you to conduct additional surveys and soil borings before approving the APD if additional information is needed to make a determination that the conditions are capable of supporting the drilling unit.
(c) Frontier areas. (1) If the design of the drilling unit you plan to use in a frontier area is unique or has not been proven for use in the proposed environment, the District Manager may require you to submit a third-party review of the unit's design. If required, you must obtain the third-party review according to § 250.915 through § 250.918. You may submit this information before submitting an APD.
(2) If you plan to drill in a frontier area, you must have a contingency plan that addresses design and operating limitations of the drilling unit. Your plan must identify the actions necessary to maintain safety and prevent damage to the environment. Actions must include the suspension, curtailment, or modification of drilling or rig operations to remedy various operational or environmental situations (e.g. vessel motion, riser offset, anchor tensions, wind speed, wave height, currents, icing or ice-loading, settling, tilt or lateral movement, resupply capability).
(d) U.S. Coast Guard (USCG) documentation. You must provide the current Certificate of Inspection or Letter of Compliance from the USCG. You must also provide current documentation of any operational limitations imposed by an appropriate classification society.
(e) Floating drilling unit. If you use a floating drilling unit, you must indicate that you have a contingency plan for moving off location in an emergency situation.
(f) Inspection of unit. The drilling unit must be available for inspection by the District Manager before commencing operations.
(g) Once the District Manager has approved a MODU for use, you do not need to re-submit the information required by this section for another APD to use the same MODU unless changes in equipment affect its rated capacity to operate in the District.
[68 FR 8423, Feb. 20, 2003, as amended at 72 FR 25201, May 4, 2007]
§ 250.418
What additional information must I submit with my APD?
You must include the following with the APD:
(a) Rated capacities of the drilling rig and major drilling equipment, if not already on file with the appropriate District office;
(b) A drilling fluids program that includes the minimum quantities of drilling fluids and drilling fluid materials, including weight materials, to be kept at the site;
(c) A proposed directional plot if the well is to be directionally drilled;
(d) A Hydrogen Sulfide Contingency Plan (see § 250.490), if applicable, and not previously submitted;
(e) A welding plan (see §§ 250.109 to 250.113) if not previously submitted;
(f) In areas subject to subfreezing conditions, evidence that the drilling equipment, BOP systems and components, diverter systems, and other associated equipment and materials are suitable for operating under such conditions;
(g) A request for approval if you plan to wash out or displace some cement to facilitate casing removal upon well abandonment; and
(h) Such other information as the District Manager may require.
[68 FR 8423, Feb. 20, 2003]

Casing and Cementing Requirements
§ 250.420
What well casing and cementing requirements must I meet?
You must case and cement all wells. Your casing and cementing programs must meet the requirements of this section and of §§ 250.421 through 250.428.
(a) Casing and cementing program requirements. Your casing and cementing programs must:
(1) Properly control formation pressures and fluids;
(2) Prevent the direct or indirect release of fluids from any stratum through the wellbore into offshore waters;
(3) Prevent communication between separate hydrocarbon-bearing strata;
(4) Protect freshwater aquifers from contamination; and
(5) Support unconsolidated sediments.
(b) Casing requirements. (1) You must design casing (including liners) to withstand the anticipated stresses imposed by tensile, compressive, and buckling loads; burst and collapse pressures; thermal effects; and combinations thereof.
(2) The casing design must include safety measures that ensure well control during drilling and safe operations during the life of the well.
(c) Cementing requirements. You must design and conduct your cementing jobs so that cement composition, placement techniques, and waiting times ensure that the cement placed behind the bottom 500 feet of casing attains a minimum compressive strength of 500 psi before drilling out of the casing or before commencing completion operations.
[68 FR 8423, Feb. 20, 2003]
§ 250.421
What are the casing and cementing requirements by type of casing string?
The table in this section identifies specific design, setting, and cementing requirements for casing strings and liners. For the purposes of subpart D, the casing strings in order of normal installation are as follows: drive or structural, conductor, surface, intermediate, and production casings (including liners). The District Manager may approve or prescribe other casing and cementing requirements where appropriate.
Casing type | Casing requirements | Cementing requirements
(a) Drive or Structural | Set by driving, jetting, or drilling to the minimum depth as approved or prescribed by the District Manager | If you drilled a portion of this hole, you must use enough cement to fill the annular space back to the mudline.
(b) Conductor | Design casing and select setting depths based on relevant engineering and geologic factors. These factors include the presence or absence of hydrocarbons, potential hazards, and water depths Set casing immediately before drilling into formations known to contain oil or gas. If you encounter oil or gas or unexpected formation pressure before the planned casing point, you must set casing immediately | Use enough cement to fill the calculated annular space back to the mudline. Verify annular fill by observing cement returns. If you cannot observe cement returns, use additional cement to ensure fill-back to the mudline. For drilling on an artificial island or when using a glory hole, you must discuss the cement fill level with the District Manager.
(c) Surface | Design casing and select setting depths based on relevant engineering and geologic factors. These factors include the presence or absence of hydrocarbons, potential hazards, and water depths | Use enough cement to fill the calculated annular space to at least 200 feet inside the conductor casing. When geologic conditions such as near-surface fractures and faulting exist, you must use enough cement to fill the calculated annular space to the mudline.
(d) Intermediate | Design casing and select setting depth based on anticipated or encountered geologic characteristics or wellbore conditions | Use enough cement to cover and isolate all hydrocarbon-bearing zones and isolate abnormal pressure intervals from normal pressure intervals in the well. As a minimum, you must cement the annular space 500 feet above the casing shoe and 500 feet above each zone to be isolated.
| (e) Production | Design casing and select setting depth based on anticipated or encountered geologic characteristics or wellbore conditions | Use enough cement to cover or isolate all hydrocarbon-bearing zones above the shoe. As a minimum, you must cement the annular space at least 500 feet above the casing shoe and 500 feet above the uppermost hydrocarbon-bearing zone.
(f) Liners | If you use a liner as conductor or surface casing, you must set the top of the liner at least 200 feet above the previous casing/liner shoe If you use a liner as an intermediate string below a surface string or production casing below an intermediate string, you must set the top of the liner at least 100 feet above the previous casing shoe. | Same as cementing requirements for specific casing types. For example, a liner used as intermediate casing must be cemented according to the cementing requirements for intermediate casing.
[68 FR 8423, Feb. 20, 2003]
§ 250.422
When may I resume drilling after cementing?
(a) After cementing surface, intermediate, or production casing (or liners), you may resume drilling after the cement has been held under pressure for 12 hours. For conductor casing, you may resume drilling after the cement has been held under pressure for 8 hours. One acceptable method of holding cement under pressure is to use float valves to hold the cement in place.
(b) If you plan to nipple down your diverter or BOP stack during the 8- or 12-hour waiting time, you must determine, before nippling down, when it will be safe to do so. You must base your determination on a knowledge of formation conditions, cement composition, effects of nippling down, presence of potential drilling hazards, well conditions during drilling, cementing, and post cementing, as well as past experience.
[68 FR 8423, Feb. 20, 2003]
§ 250.423
What are the requirements for pressure testing casing?
The table in this section describes the minimum test pressures for each string of casing. You may not resume drilling or other down-hole operations until you obtain a satisfactory pressure test. If the pressure declines more than 10 percent in a 30-minute test or if there is another indication of a leak, you must re-cement, repair the casing, or run additional casing to provide a proper seal. The District Manager may approve or require other casing test pressures.
Casing type | Minimum test pressure
(a) Drive or Structural | Not required
(b) Conductor | 200 psi
(c) Surface, Intermediate, and Production | 70 percent of its minimum internal yield
[68 FR 8423, Feb. 20, 2003]
§ 250.424
What are the requirements for prolonged drilling operations?
If wellbore operations continue for more than 30 days within a casing string run to the surface:
(a) You must stop drilling operations as soon as practicable, and evaluate the effects of the prolonged operations on continued drilling operations and the life of the well. At a minimum, you must:
(1) Caliper or pressure test the casing; and
(2) Report the results of your evaluation to the District Manager and obtain approval of those results before resuming operations.
(b) If casing integrity has deteriorated to a level below minimum safety factors, you must:
(1) Repair the casing or run another casing string; and
(2) Obtain approval from the District Manager before you begin repairs.
[68 FR 8423, Feb. 20, 2003]
§ 250.425
What are the requirements for pressure testing liners?
(a) You must test each drilling liner (and liner-lap) to a pressure at least equal to the anticipated pressure to which the liner will be subjected during the formation pressure-integrity test below that liner shoe, or subsequent liner shoes if set. The District Manager may approve or require other liner test pressures.
(b) You must test each production liner (and liner-lap) to a minimum of 500 psi above the formation fracture pressure at the casing shoe into which the liner is lapped.
(c) You may not resume drilling or other down-hole operations until you obtain a satisfactory pressure test. If the pressure declines more than 10 percent in a 30-minute test or if there is another indication of a leak, you must re-cement, repair the liner, or run additional casing/liner to provide a proper seal.
[68 FR 8423, Feb. 20, 2003]
§ 250.426
What are the recordkeeping requirements for casing and liner pressure tests?
You must record the time, date, and results of each pressure test in the driller's report maintained under standard industry practice. In addition, you must record each test on a pressure chart and have your onsite representative sign and date the test as being correct.
[68 FR 8423, Feb. 20, 2003]
§ 250.427
What are the requirements for pressure integrity tests?
You must conduct a pressure integrity test below the surface casing or liner and all intermediate casings or liners. The District Manager may require you to run a pressure-integrity test at the conductor casing shoe if warranted by local geologic conditions or the planned casing setting depth. You must conduct each pressure integrity test after drilling at least 10 feet but no more than 50 feet of new hole below the casing shoe. You must test to either the formation leak-off pressure or to an equivalent drilling fluid weight if identified in an approved APD.
(a) You must use the pressure integrity test and related hole-behavior observations, such as pore-pressure test results, gas-cut drilling fluid, and well kicks to adjust the drilling fluid program and the setting depth of the next casing string. You must record all test results and hole-behavior observations made during the course of drilling related to formation integrity and pore pressure in the driller's report.
(b) While drilling, you must maintain the safe drilling margin identified in the approved APD. When you cannot maintain this safe margin, you must suspend drilling operations and remedy the situation.
[68 FR 8423, Feb. 20, 2003]
§ 250.428
What must I do in certain cementing and casing situations?
The table in this section describes actions that lessees must take when certain situations occur during casing and cementing activities.
If you encounter the following situation: | Then you must . . .
(a) Have unexpected formation pressures or conditions that warrant revising your casing design | Submit a revised casing program to the District Manager for approval.
(b) Need to increase casing setting depths more than 100 feet true vertical depth (TVD) from the approved APD due to conditions encountered during drilling operations | Submit those changes to the District Manager for approval.
(c) Have indication of inadequate cement job (such as lost returns, cement channeling, or failure of equipment) | (1) Pressure test the casing shoe; (2) Run a temperature survey; (3) Run a cement bond log; or (4) Use a combination of these techniques.
(d) Inadequate cement job | Re-cement or take other remedial actions as approved by the District Manager.
(e) Primary cement job that did not isolate abnormal pressure intervals | Isolate those intervals from normal pressures by squeeze cementing before you complete; suspend operations; or abandon the well, whichever occurs first.
(f) Decide to produce a well that was not originally contemplated for production | Have at least two cemented casing strings (does not include liners) in the well. Note: All producing wells must have at least two cemented casing strings.
(g) Want to drill a well without setting conductor casing | Submit geologic data and information to the District Manager that demonstrates the absence of shallow hydrocarbons or hazards. This information must include logging and drilling fluid-monitoring from wells previously drilled within 500 feet of the proposed well path down to the next casing point.
| (h) Need to use less than required cement for the surface casing during floating drilling operations to provide protection from burst and collapse pressures | Submit information to the District Manager that demonstrates the use of less cement is necessary.
(i) Cement across a permafrost zone | Use cement that sets before it freezes and has a low heat of hydration.
(j) Leave the annulus opposite a permafrost zone uncemented | Fill the annulus with a liquid that has a freezing point below the minimum permafrost temperature and minimizes opposite a corrosion.
[68 FR 8423, Feb. 20, 2003]

Diverter System Requirements
§ 250.430
When must I install a diverter system?
You must install a diverter system before you drill a conductor or surface hole. The diverter system consists of a diverter sealing element, diverter lines, and control systems. You must design, install, use, maintain, and test the diverter system to ensure proper diversion of gases, water, drilling fluid, and other materials away from facilities and personnel.
[68 FR 8423, Feb. 20, 2003]
§ 250.431
What are the diverter design and installation requirements?
You must design and install your diverter system to:
(a) Use diverter spool outlets and diverter lines that have a nominal diameter of at least 10 inches for surface wellhead configurations and at least 12 inches for floating drilling operations;
(b) Use dual diverter lines arranged to provide for downwind diversion capability;
(c) Use at least two diverter control stations. One station must be on the drilling floor. The other station must be in a readily accessible location away from the drilling floor;
(d) Use only remote-controlled valves in the diverter lines. All valves in the diverter system must be full-opening. You may not install manual or butterfly valves in any part of the diverter system;
(e) Minimize the number of turns (only one 90-degree turn allowed for each line for bottom-founded drilling units) in the diverter lines, maximize the radius of curvature of turns, and target all right angles and sharp turns;
(f) Anchor and support the entire diverter system to prevent whipping and vibration; and
(g) Protect all diverter-control instruments and lines from possible damage by thrown or falling objects.
[68 FR 8423, Feb. 20, 2003]
§ 250.432
How do I obtain a departure to diverter design and installation requirements?
The table below describes possible departures from the diverter requirements and the conditions required for each departure. To obtain one of these departures, you must have discussed the departure in your APD and received approval from the District Manager.
If you want a departure to: | Then you must...
(a) Use flexible hose for diverter lines instead of rigid pipe | Use flexible hose that has integral end couplings.
(b) Use only one spool outlet for your diverter system | (1) Have branch lines that meet the minimum internal diameter requirements; and (2) Provide downwind diversion capability.
(c) Use a spool with an outlet with an internal diameter of less than 10 inches on a surface wellhead | Use a spool that has dual outlets with an internal diameter of at least 8 inches.
(d) Use a single diverter line for floating drilling operations on a dynamically positioned drillship | Maintain an appropriate vessel heading to provide for downwind diversion.
[68 FR 8423, Feb. 20, 2003]
§ 250.433
What are the diverter actuation and testing requirements?
When you install the diverter system, you must actuate the diverter sealing element, diverter valves, and diverter-control systems and control stations. You must also flow-test the vent lines.
(a) For drilling operations with a surface wellhead configuration, you must actuate the diverter system at least once every 24-hour period after the initial test. After you have nippled up on conductor casing, you must pressure-test the diverter-sealing element and diverter valves to a minimum of 200 psi. While the diverter is installed, you must conduct subsequent pressure tests within 7 days after the previous test.
(b) For floating drilling operations with a subsea BOP stack, you must actuate the diverter system within 7 days after the previous actuation.
(c) You must alternate actuations and tests between control stations.
[68 FR 8423, Feb. 20, 2003]
§ 250.434
What are the recordkeeping requirements for diverter actuations and tests?
You must record the time, date, and results of all diverter actuations and tests in the driller's report. In addition, you must:
(a) Record the diverter pressure test on a pressure chart;
(b) Require your onsite representative to sign and date the pressure test chart;
(c) Identify the control station used during the test or actuation;
(d) Identify problems or irregularities observed during the testing or actuations and record actions taken to remedy the problems or irregularities; and
(e) Retain all pressure charts and reports pertaining to the diverter tests and actuations at the facility for the duration of drilling the well.
[68 FR 8423, Feb. 20, 2003]

Blowout Preventer (BOP) System Requirements
§ 250.440
What are the general requirements for BOP systems and system components?
You must design, install, maintain, test, and use the BOP system and system components to ensure well control. The working-pressure rating of each BOP component must exceed maximum anticipated surface pressures. The BOP system includes the BOP stack and associated BOP systems and equipment.
[68 FR 8423, Feb. 20, 2003]
§ 250.441
What are the requirements for a surface BOP stack?
(a) When you drill with a surface BOP stack, you must install the BOP system before drilling below surface casing. The surface BOP stack must include at least four remote-controlled, hydraulically operated BOPs, consisting of an annular BOP, two BOPs equipped with pipe rams, and one BOP equipped with blind or blind-shear rams.
(b) No later than February 21, 2006, your surface BOP stack must include at least four remote-controlled, hydraulically operated BOPs consisting of an annular BOP, two BOPs equipped with pipe rams, and one BOP equipped with blind-shear rams. The blind-shear rams must be capable of shearing the drill pipe that is in the hole.
(c) You must install an accumulator system that provides 1.5 times the volume of fluid capacity necessary to close and hold closed all BOP components. The system must perform with a minimum pressure of 200 psi above the precharge pressure without assistance from a charging system. If you supply the accumulator regulators by rig air and do not have a secondary source of pneumatic supply, you must equip the regulators with manual overrides or other devices to ensure capability of hydraulic operations if rig air is lost.
(d) In addition to the stack and accumulator system, you must install the associated BOP systems and equipment required by the regulations in this subpart.
[68 FR 8423, Feb. 20, 2003]
§ 250.442
What are the requirements for a subsea BOP stack?
(a) When you drill with a subsea BOP stack, you must install the BOP system before drilling below surface casing. The District Manager may require you to install a subsea BOP system before drilling below the conductor casing if proposed casing setting depths or local geology indicate the need.
(b) Your subsea BOP stack must include at least four remote-controlled, hydraulically operated BOPs consisting of an annular BOP, two BOPs equipped with pipe rams, and one BOP equipped with blind-shear rams.
(c) You must install an accumulator closing system to provide fast closure of the BOP components and to operate all critical functions in case of a loss of the power fluid connection to the surface. The accumulator system must meet or exceed the provisions of Section 13.3, Accumulator Volumetric Capacity, in API RP 53, Recommended Practices for Blowout Prevention Equipment Systems for Drilling Wells (incorporated by reference as specified in § 250.198). The District Manager may approve a suitable alternative method.
(d) The BOP system must include an operable dual-pod control system to ensure proper and independent operation of the BOP system.
(e) Before removing the marine riser, you must displace the riser with seawater. You must maintain sufficient hydrostatic pressure or take other suitable precautions to compensate for the reduction in pressure and to maintain a safe and controlled well condition.
[68 FR 8423, Feb. 20, 2003]
§ 250.443
What associated systems and related equipment must all BOP systems include?
All BOP systems must include the following associated systems and related equipment:
(a) An automatic backup to the primary accumulator-charging system. The power source must be independent from the power source for the primary accumulator-charging system. The independent power source must possess sufficient capability to close and hold closed all BOP components.
(b) At least two BOP control stations. One station must be on the drilling floor. You must locate the other station in a readily accessible location away from the drilling floor.
(c) Side outlets on the BOP stack for separate kill and choke lines. If your stack does not have side outlets, you must install a drilling spool with side outlets.
(d) A choke and a kill line on the BOP stack. You must equip each line with two full-opening valves, one of which must be remote-controlled. For a subsea BOP system, both valves in each line must be remote-controlled. In addition:
(1) You must install the choke line above the bottom ram;
(2) You may install the kill line below the bottom ram; and
(3) For a surface BOP system, on the kill line you may install a check valve and a manual valve instead of the remote-controlled valve. To use this configuration, both manual valves must be readily accessible and you must install the check valve between the manual valves and the pump.
(e) A fill-up line above the uppermost BOP.
(f) Locking devices installed on the ram-type BOPs.
(g) A wellhead assembly with a rated working pressure that exceeds the maximum anticipated surface pressure.
[68 FR 8423, Feb. 20, 2003]
§ 250.444
What are the choke manifold requirements?
(a) Your BOP system must include a choke manifold that is suitable for the anticipated surface pressures, anticipated methods of well control, the surrounding environment, and the corrosiveness, volume, and abrasiveness of drilling fluids and well fluids that you may encounter.
(b) Choke manifold components must have a rated working pressure at least as great as the rated working pressure of the ram BOPs. If your choke manifold has buffer tanks downstream of choke assemblies, you must install isolation valves on any bleed lines.
(c) Valves, pipes, flexible steel hoses, and other fittings upstream of the choke manifold must have a rated working pressure at least as great as the rated working pressure of the ram BOPs.
[68 FR 8423, Feb. 20, 2003]
§ 250.445
What are the requirements for kelly valves, inside BOPs, and drill-string safety valves?
You must use or provide the following BOP equipment during drilling operations:
(a) A kelly valve installed below the swivel (upper kelly valve);
(b) A kelly valve installed at the bottom of the kelly (lower kelly valve). You must be able to strip the lower kelly valve through the BOP stack;
(c) If you drill with a mud motor and use drill pipe instead of a kelly, you must install one kelly valve above, and one strippable kelly valve below, the joint of drill pipe used in place of a kelly;
(d) On a top-drive system equipped with a remote-controlled valve, you must install a strippable kelly-type valve below the remote-controlled valve;
(e) An inside BOP in the open position located on the rig floor. You must be able to install an inside BOP for each size connection in the drill string;
(f) A drill-string safety valve in the open position located on the rig floor. You must have a drill-string safety valve available for each size connection in the drill string;
(g) When running casing, you must have a safety valve in the open position available on the rig floor to fit the casing string being run in the hole;
(h) All required manual and remote-controlled kelly valves, drill-string safety valves, and comparable-type valves (i.e. kelly-type valve in a top-drive system) must be essentially full-opening; and
(i) The drilling crew must have ready access to a wrench to fit each manual valve.
[68 FR 8423, Feb. 20, 2003]
§ 250.446
What are the BOP maintenance and inspection requirements?
(a) You must maintain your BOP system to ensure that the equipment functions properly. BOP maintenance must meet or exceed the provisions of Sections 17.10 and 18.10, Inspections; Sections 17.11 and 18.11, Maintenance; and Sections 17.12 and 18.12, Quality Management, described in API RP 53, Recommended Practices for Blowout Prevention Equipment Systems for Drilling Wells (incorporated by reference as specified in § 250.198).
(b) You must visually inspect your surface BOP system on a daily basis. You must visually inspect your subsea BOP system and marine riser at least once every 3 days if weather and sea conditions permit. You may use television cameras to inspect subsea equipment.
[68 FR 8423, Feb. 20, 2003]
§ 250.447
When must I pressure test the BOP system?
You must pressure test your BOP system (this includes the choke manifold, kelly valves, inside BOP, and drill-string safety valve):
(a) When installed;
(b) Before 14 days have elapsed since your last BOP pressure test. You must begin to test your BOP system before midnight on the 14th day following the conclusion of the previous test. However, the District Manager may require more frequent testing if conditions or BOP performance warrant; and
(c) Before drilling out each string of casing or a liner. The District Manager may allow you to omit this test if you didn't remove the BOP stack to run the casing string or liner and the required BOP test pressures for the next section of the hole are not greater than the test pressures for the previous BOP test. You must indicate in your APD which casing strings and liners meet these criteria.
[68 FR 8423, Feb. 20, 2003]
§ 250.448
What are the BOP pressure tests requirements?
When you pressure test the BOP system, you must conduct a low-pressure and a high-pressure test for each BOP component. You must conduct the low-pressure test before the high-pressure test. Each individual pressure test must hold pressure long enough to demonstrate that the tested component(s) holds the required pressure. Required test pressures are as follows:
(a) Low-pressure test. All low-pressure tests must be between 200 and 300 psi. Any initial pressure above 300 psi must be bled back to a pressure between 200 and 300 psi before starting the test. If the initial pressure exceeds 500 psi, you must bleed back to zero and reinitiate the test.
(b) High-pressure test for ram-type BOPs, the choke manifold, and other BOP components. The high-pressure test must equal the rated working pressure of the equipment or be 500 psi greater than your calculated maximum anticipated surface pressure (MASP) for the applicable section of hole. Before you may test BOP equipment to the MASP plus 500 psi, the District Manager must have approved those test pressures in your APD.
(c) High pressure test for annular-type BOPs. The high pressure test must equal 70 percent of the rated working pressure of the equipment or to a pressure approved in your APD.
(d) Duration of pressure test. Each test must hold the required pressure for 5 minutes. However, for surface BOP systems and surface equipment of a subsea BOP system, a 3-minute test duration is acceptable if you record your test pressures on the outermost half of a 4-hour chart, on a 1-hour chart, or on a digital recorder. If the equipment does not hold the required pressure during a test, you must correct the problem and retest the affected component(s).
[68 FR 8423, Feb. 20, 2003]
§ 250.449
What additional BOP testing requirements must I meet?
You must meet the following additional BOP testing requirements:
(a) Use water to test a surface BOP system;
(b) Stump test a subsea BOP system before installation. You must use water to conduct this test. You may use drilling fluids to conduct subsequent tests of a subsea BOP system;
(c) Alternate tests between control stations and pods;
(d) Pressure test the blind or blind-shear ram BOP during stump tests and at all casing points;
(e) The interval between any blind or blind-shear ram BOP pressure tests may not exceed 30 days;
(f) Pressure test variable bore-pipe ram BOPs against the largest and smallest sizes of pipe in use, excluding drill collars and bottom-hole tools;
(g) Pressure test affected BOP components following the disconnection or repair of any well-pressure containment seal in the wellhead or BOP stack assembly;
(h) Function test annular and ram BOPs every 7 days between pressure tests; and
(i) Actuate safety valves assembled with proper casing connections before running casing.
[68 FR 8423, Feb. 20, 2003]
§ 250.450
What are the recordkeeping requirements for BOP tests?
You must record the time, date, and results of all pressure tests, actuations, and inspections of the BOP system, system components, and marine riser in the driller's report. In addition, you must:
(a) Record BOP test pressures on pressure charts;
(b) Require your onsite representative to sign and date BOP test charts and reports as correct;
(c) Document the sequential order of BOP and auxiliary equipment testing and the pressure and duration of each test. For subsea BOP systems, you must also record the closing times for annular and ram BOPs. You may reference a BOP test plan if it is available at the facility;
(d) Identify the control station and pod used during the test;
(e) Identify any problems or irregularities observed during BOP system testing and record actions taken to remedy the problems or irregularities; and
(f) Retain all records, including pressure charts, driller's report, and referenced documents pertaining to BOP tests, actuations, and inspections at the facility for the duration of drilling.
[68 FR 8423, Feb. 20, 2003]
§ 250.451
What must I do in certain situations involving BOP equipment or systems?
The table in this section describes actions that lessees must take when certain situations occur with BOP systems during drilling activities.
If you encounter the following situation: | Then you must . . .
(a) BOP equipment does not hold the required pressure during a test | Correct the problem and retest the affected equipment.
(b) Need to repair or replace a surface or subsea BOP system | First place the well in a safe, controlled condition (e.g., before drilling out a casing shoe or after setting a cement plug, bridge plug, or a packer).
(c) Need to postpone a BOP test due to well-control problems such as lost circulation, formation fluid influx, or stuck drill pipe | Record the reason for postponing the test in the driller's report and conduct the required BOP test on the first trip out of the hole.
(d) BOP control station or pod that does not function properly | Suspend further drilling operations until that station or pod is operable.
(e) Want to drill with a tapered drill-string | Install two or more sets of conventional or variable-bore pipe rams in the BOP stack to provide for the following: two sets of rams must be capable of sealing around the larger-size drill string and one set of pipe rams must be capable of sealing around the smaller-size drill string.
(f) Install casing rams in a BOP stack | Test the ram bonnets before running casing.
(g) Want to use an annular BOP with a rated working pressure less than the anticipated surface pressure | Demonstrate that your well control procedures or the anticipated well conditions will not place demands above its rated working pressure and obtain approval from the District Manager.
(h) Use a subsea BOP system in an ice-scour area | Install the BOP stack in a glory hole. The glory hole must be deep enough to ensure that the top of the stack is below the deepest probable ice-scour depth.
[68 FR 8423, Feb. 20, 2003]

Drilling Fluid Requirements
§ 250.455
What are the general requirements for a drilling fluid program?
You must design and implement your drilling fluid program to prevent the loss of well control. This program must address drilling fluid safe practices, testing and monitoring equipment, drilling fluid quantities, and drilling fluid-handling areas.
[68 FR 8423, Feb. 20, 2003]
§ 250.456
What safe practices must the drilling fluid program follow?
Your drilling fluid program must include the following safe practices:
(a) Before starting out of the hole with drill pipe, you must properly condition the drilling fluid. You must circulate a volume of drilling fluid equal to the annular volume with the drill pipe just off-bottom. You may omit this practice if documentation in the driller's report shows:
(1) No indication of formation fluid influx before starting to pull the drill pipe from the hole;
(2) The weight of returning drilling fluid is within 0.2 pounds per gallon (1.5 pounds per cubic foot) of the drilling fluid entering the hole; and
(3) Other drilling fluid properties are within the limits established by the program approved in the APD.
(b) Record each time you circulate drilling fluid in the hole in the driller's report;
(c) When coming out of the hole with drill pipe, you must fill the annulus with drilling fluid before the hydrostatic pressure decreases by 75 psi, or every five stands of drill pipe, whichever gives a lower decrease in hydrostatic pressure. You must calculate the number of stands of drill pipe and drill collars that you may pull before you must fill the hole. You must also calculate the equivalent drilling fluid volume needed to fill the hole. Both sets of numbers must be posted near the driller's station. You must use a mechanical, volumetric, or electronic device to measure the drilling fluid required to fill the hole;
(d) You must run and pull drill pipe and downhole tools at controlled rates so you do not swab or surge the well;
(e) When there is an indication of swabbing or influx of formation fluids, you must take appropriate measures to control the well. You must circulate and condition the well, on or near-bottom, unless well or drilling-fluid conditions prevent running the drill pipe back to the bottom;
(f) You must calculate and post near the driller's console the maximum pressures that you may safely contain under a shut-in BOP for each casing string. The pressures posted must consider the surface pressure at which the formation at the shoe would break down, the rated working pressure of the BOP stack, and 70 percent of casing burst (or casing test as approved by the District Manager). As a minimum, you must post the following two pressures:
(1) The surface pressure at which the shoe would break down. This calculation must consider the current drilling fluid weight in the hole; and
(2) The lesser of the BOP's rated working pressure or 70 percent of casing-burst pressure (or casing test otherwise approved by the District Manager);
(g) You must install an operable drilling fluid-gas separator and degasser before you begin drilling operations. You must maintain this equipment throughout the drilling of the well;
(h) Before pulling drill-stem test tools from the hole, you must circulate or reverse-circulate the test fluids in the hole. If circulating out test fluids is not feasible, you may bullhead test fluids out of the drill-stem test string and tools with an appropriate kill weight fluid;
(i) When circulating, you must test the drilling fluid at least once each tour, or more frequently if conditions warrant. Your tests must conform to industry-accepted practices and include density, viscosity, and gel strength; hydrogenion concentration; filtration; and any other tests the District Manager requires for monitoring and maintaining drilling fluid quality, prevention of downhole equipment problems and for kick detection. You must record the results of these tests in the drilling fluid report; and
(j) In areas where permafrost and/or hydrate zones are present or may be present, you must control drilling fluid temperatures to drill safely through those zones.
[68 FR 8423, Feb. 20, 2003; 68 FR 14274, Mar. 24, 2003]
§ 250.457
What equipment is required to monitor drilling fluids?
Once you establish drilling fluid returns, you must install and maintain the following drilling fluid-system monitoring equipment throughout subsequent drilling operations. This equipment must have the following indicators on the rig floor:
(a) Pit level indicator to determine drilling fluid-pit volume gains and losses. This indicator must include both a visual and an audible warning device;
(b) Volume measuring device to accurately determine drilling fluid volumes required to fill the hole on trips;
(c) Return indicator devices that indicate the relationship between drilling fluid-return flow rate and pump discharge rate. This indicator must include both a visual and an audible warning device; and
(d) Gas-detecting equipment to monitor the drilling fluid returns. The indicator may be located in the drilling fluid-logging compartment or on the rig floor. If the indicators are only in the logging compartment, you must continually man the equipment and have a means of immediate communication with the rig floor. If the indicators are on the rig floor only, you must install an audible alarm.
[68 FR 8423, Feb. 20, 2003]
§ 250.458
What quantities of drilling fluids are required?
(a) You must use, maintain, and replenish quantities of drilling fluid and drilling fluid materials at the drill site as necessary to ensure well control. You must determine those quantities based on known or anticipated drilling conditions, rig storage capacity, weather conditions, and estimated time for delivery.
(b) You must record the daily inventories of drilling fluid and drilling fluid materials, including weight materials and additives in the drilling fluid report.
(c) If you do not have sufficient quantities of drilling fluid and drilling fluid material to maintain well control, you must suspend drilling operations.
[68 FR 8423, Feb. 20, 2003]
§ 250.459
What are the safety requirements for drilling fluid-handling areas?
You must classify drilling fluid-handling areas according to API RP 500, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities, Classified as Class I, Division 1 and Division 2 (incorporated by reference as specified in § 250.198); or API RP 505, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities, Classified as Class 1, Zone 0, Zone 1, and Zone 2 (incorporated by reference as specified in § 250.198). In areas where dangerous concentrations of combustible gas may accumulate, you must install and maintain a ventilation system and gas monitors. Drilling fluid-handling areas must have the following safety equipment:
(a) A ventilation system capable of replacing the air once every 5 minutes or 1.0 cubic feet of air-volume flow per minute, per square foot of area, whichever is greater. In addition:
(1) If natural means provide adequate ventilation, then a mechanical ventilation system is not necessary;
(2) If a mechanical system does not run continuously, then it must activate when gas detectors indicate the presence of 1 percent or more of combustible gas by volume; and
(3) If discharges from a mechanical ventilation system may be hazardous, then you must maintain the drilling fluid-handling area at a negative pressure. You must protect the negative pressure area by using at least one of the following: a pressure-sensitive alarm, open-door alarms on each access to the area, automatic door-closing devices, air locks, or other devices approved by the District Manager;
(b) Gas detectors and alarms except in open areas where adequate ventilation is provided by natural means. You must test and recalibrate gas detectors quarterly. No more than 90 days may elapse between tests;
(c) Explosion-proof or pressurized electrical equipment to prevent the ignition of explosive gases. Where you use air for pressuring equipment, you must locate the air intake outside of and as far as practicable from hazardous areas; and
(d) Alarms that activate when the mechanical ventilation system fails.
[68 FR 8423, Feb. 20, 2003]

Other Drilling Requirements
§ 250.460
What are the requirements for conducting a well test?
(a) If you intend to conduct a well test, you must include your projected plans for the test with your APD (form MMS-123) or in an Application for Permit to Modify (APM) (form MMS-124). Your plans must include at least the following information:
(1) Estimated flowing and shut-in tubing pressures;
(2) Estimated flow rates and cumulative volumes;
(3) Time duration of flow, buildup, and drawdown periods;
(4) Description and rating of surface and subsurface test equipment;
(5) Schematic drawing, showing the layout of test equipment;
(6) Description of safety equipment, including gas detectors and fire-fighting equipment;
(7) Proposed methods to handle or transport produced fluids; and
(8) Description of the test procedures.
(b) You must give the District Manager at least 24-hours notice before starting a well test.
[68 FR 8423, Feb. 20, 2003]
§ 250.461
What are the requirements for directional and inclination surveys?
For this subpart, MMS classifies a well as vertical if the calculated average of inclination readings does not exceed 3 degrees from the vertical.
(a) Survey requirements for a vertical well. (1) You must conduct inclination surveys on each vertical well and record the results. Survey intervals may not exceed 1,000 feet during the normal course of drilling;
(2) You must also conduct a directional survey that provides both inclination and azimuth, and digitally record the results in electronic format:
(i) Within 500 feet of setting surface or intermediate casing;
(ii) Within 500 feet of setting any liner; and
(iii) When you reach total depth.
(b) Survey requirements for directional well. You must conduct directional surveys on each directional well and digitally record the results. Surveys must give both inclination and azimuth at intervals not to exceed 500 feet during the normal course of drilling. Intervals during angle-changing portions of the hole may not exceed 100 feet.
(c) Measurement while drilling. You may use measurement-while-drilling technology if it meets the requirements of this section.
(d) Composite survey requirements. (1) Your composite directional survey must show the interval from the bottom of the conductor casing to total depth. In the absence of conductor casing, the survey must show the interval from the bottom of the drive or structural casing to total depth; and
(2) You must correct all surveys to Universal-Transverse-Mercator-Grid-north or Lambert-Grid-north after making the magnetic-to-true-north correction. Surveys must show the magnetic and grid corrections used and include a listing of the directionally computed inclinations and azimuths.
(e) If you drill within 500 feet of an adjacent lease, the Regional Supervisor may require you to furnish a copy of the well's directional survey to the affected leaseholder. This could occur when the adjoining leaseholder requests a copy of the survey for the protection of correlative rights.
[68 FR 8423, Feb. 20, 2003]
§ 250.462
What are the requirements for well-control drills?
You must conduct a weekly well-control drill with each drilling crew. Your drill must familiarize the crew with its roles and functions so that all crew members can perform their duties promptly and efficiently.
(a) Well-control drill plan. You must prepare a well control drill plan for each well. Your plan must outline the assignments for each crew member and establish times to complete each portion of the drill. You must post a copy of the well control drill plan on the rig floor or bulletin board.
(b) Timing of drills. You must conduct each drill during a period of activity that minimizes the risk to drilling operations. The timing of your drills must cover a range of different operations, including drilling with a diverter, on-bottom drilling, and tripping.
(c) Recordkeeping requirements. For each drill, you must record the following in the driller's report:
(1) The time to be ready to close the diverter or BOP system; and
(2) The total time to complete the entire drill.
(d) MMS ordered drill. An MMS authorized representative may require you to conduct a well control drill during an MMS inspection. The MMS representative will consult with your onsite representative before requiring the drill.
[68 FR 8423, Feb. 20, 2003]
§ 250.463
Who establishes field drilling rules?
(a) The District Manager may establish field drilling rules different from the requirements of this subpart when geological and engineering information shows that specific operating requirements are appropriate. You must comply with field drilling rules and nonconflicting requirements of this subpart. The District Manager may amend or cancel field drilling rules at any time.
(b) You may request the District Manager to establish, amend, or cancel field drilling rules.
[68 FR 8423, Feb. 20, 2003]

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 MMS?
(a) You must submit an APM (form MMS-124) or an End of Operations Report (form MMS-125) and other materials to the Regional Supervisor as shown in the following table. You must also submit a public information copy of each form.
When you | Then you must | And
(1) Intend to revise your drilling plan, change major drilling equipment, or plugback | Submit form MMS-124 or request oral approval | Receive written or oral approval from the District Manager before you begin the intended operation. If you get an approval, you must submit form MMS-124 no later than the end of the 3rd business day following the oral approval. In all cases, or you must meet the additional requirements in paragraph (b) of this section.
| (2) Determine a well's final surface location, water depth, and the rotary kelly bushing elevation | Immediately Submit a form MMS-124 | Submit a plat certified by a registered land surveyor that meets the requirements of § 250.412.
(3) Move a drilling unit from a wellbore before completing a well | Submit forms MMS-124 and MMS-125 within 30 days after the suspension of wellbore operations | Submit appropriate copies of the well records.
(b) If you intend to perform any of the actions specified in paragraph (a)(1) of this section, you must meet the following additional requirements:
(1) Your APM (Form MMS-124) must contain a detailed statement of the proposed work that would materially change from the approved APD. The submission of your APM must be accompanied by payment of the service fee listed in § 250.125;
(2) Your form MMS-124 must include the present status of the well, depth of all casing strings set to date, well depth, present production zones and productive capability, and all other information specified; and
(3) Within 30 days after completing this work, you must submit form MMS-124 with detailed information about the work to the District Manager, unless you have already provided sufficient information in a Well Activity Report, form MMS-133 (§ 250.468(b)).
[68 FR 8423, Feb. 20, 2003, as amended at 71 FR 40911, July 19, 2006]
§ 250.466
What records must I keep?
You must keep complete, legible, and accurate records for each well. You must keep drilling records onsite while drilling activities continue. After completion of drilling activities, you must keep all drilling and other well records for the time periods shown in § 250.467. You may keep these records at a location of your choice. The records must contain complete information on all of the following:
(a) Well operations;
(b) Descriptions of formations penetrated;
(c) Content and character of oil, gas, water, and other mineral deposits in each formation;
(d) Kind, weight, size, grade, and setting depth of casing;
(e) All well logs and surveys run in the wellbore;
(f) Any significant malfunction or problem; and
(g) All other information required by the District Manager in the interests of resource evaluation, waste prevention, conservation of natural resources, and the protection of correlative rights, safety, and environment.
[68 FR 8423, Feb. 20, 2003, as amended at 72 FR 25201, May 4, 2007]
§ 250.467
How long must I keep records?
You must keep records for the time periods shown in the following table.
You must keep records relating to | Until
(a) Drilling | Ninety days after you complete drilling operations.
(b) Casing and liner pressure tests, diverter tests, and BOP tests | Two years after the completion of drilling operations.
(c) Completion of a well or of any workover activity that materially alters the completion configuration or affects a hydrocarbon-bearing zone | You permanently plug and abandon the well or until you forward the records with a lease assignment.
[68 FR 8423, Feb. 20, 2003]
§ 250.468
What well records am I required to submit?
(a) You must submit copies of logs or charts of electrical, radioactive, sonic, and other well-logging operations; directional and vertical-well surveys; velocity profiles and surveys; and analysis of cores to MMS. Each Region will provide specific instructions for submitting well logs and surveys.
(b) For drilling operations in the GOM OCS Region, you must submit form MMS-133, Well Activity Report, to the District Manager on a weekly basis.
(c) For drilling operations in the Pacific or Alaska OCS Regions, you must submit form MMS-133, Well Activity Report, to the District Manager on a daily basis.
[68 FR 8423, Feb. 20, 2003]
§ 250.469
What other well records could I be required to submit?
The District Manager or Regional Supervisor may require you to submit copies of any or all of the following well records.
(a) Well records as specified in § 250.466;
(b) Paleontological interpretations or reports identifying microscopic fossils by depth and/or washed samples of drill cuttings that you normally maintain for paleontological determinations. The Regional Supervisor may issue a Notice to Lessees that prescribes the manner, timeframe, and format for submitting this information;
(c) Service company reports on cementing, perforating, acidizing, testing, or other similar services; or
(d) Other reports and records of operations.
[68 FR 8423, Feb. 20, 2003]

Hydrogen Sulfide
§ 250.490
Hydrogen sulfide.
(a) What precautions must I take when operating in an H 2 S area? You must:
(1) Take all necessary and feasible precautions and measures to protect personnel from the toxic effects of H2S and to mitigate damage to property and the environment caused by H2S. You must follow the requirements of this section when conducting drilling, well-completion/well-workover, and production operations in zones with H2S present and when conducting operations in zones where the presence of H2S is unknown. You do not need to follow these requirements when operating in zones where the absence of H2S has been confirmed; and
(2) Follow your approved contingency plan.
(b) Definitions. Terms used in this section have the following meanings:
Facility means a vessel, a structure, or an artificial island used for drilling, well-completion, well-workover, and/or production operations.
H 2 S absent means:
(1) Drilling, logging, coring, testing, or producing operations have confirmed the absence of H2S in concentrations that could potentially result in atmospheric concentrations of 20 ppm or more of H2S; or
(2) Drilling in the surrounding areas and correlation of geological and seismic data with equivalent stratigraphic units have confirmed an absence of H2S throughout the area to be drilled.
H 2 S present means that drilling, logging, coring, testing, or producing operations have confirmed the presence of H2S in concentrations and volumes that could potentially result in atmospheric concentrations of 20 ppm or more of H2S.
H 2 S unknown means the designation of a zone or geologic formation where neither the presence nor absence of H2S has been confirmed.
Well-control fluid means drilling mud and completion or workover fluid as appropriate to the particular operation being conducted.
(c) Classifying an area for the presence of H 2 S. You must:
(1) Request and obtain an approved classification for the area from the Regional Supervisor before you begin operations. Classifications are “H2S absent,” H2S present,” or “H2S unknown”;
(2) Submit your request with your application for permit to drill;
(3) Support your request with available information such as geologic and geophysical data and correlations, well logs, formation tests, cores and analysis of formation fluids; and
(4) Submit a request for reclassification of a zone when additional data indicate a different classification is needed.
(d) What do I do if conditions change? If you encounter H2S that could potentially result in atmospheric concentrations of 20 ppm or more in areas not previously classified as having H2S present, you must immediately notify MMS and begin to follow requirements for areas with H2S present.
(e) What are the requirements for conducting simultaneous operations? When conducting any combination of drilling, well-completion, well-workover, and production operations simultaneously, you must follow the requirements in the section applicable to each individual operation.
(f) Requirements for submitting an H 2 S Contingency Plan. Before you begin operations, you must submit an H2S Contingency Plan to the District Manager for approval. Do not begin operations before the District Manager approves your plan. You must keep a copy of the approved plan in the field, and you must follow the plan at all times. Your plan must include:
(1) Safety procedures and rules that you will follow concerning equipment, drills, and smoking;
(2) Training you provide for employees, contractors, and visitors;
(3) Job position and title of the person responsible for the overall safety of personnel;
(4) Other key positions, how these positions fit into your organization, and what the functions, duties, and responsibilities of those job positions are;
(5) Actions that you will take when the concentration of H2S in the atmosphere reaches 20 ppm, who will be responsible for those actions, and a description of the audible and visual alarms to be activated;
(6) Briefing areas where personnel will assemble during an H2S alert. You must have at least two briefing areas on each facility and use the briefing area that is upwind of the H2S source at any given time;
(7) Criteria you will use to decide when to evacuate the facility and procedures you will use to safely evacuate all personnel from the facility by vessel, capsule, or lifeboat. If you use helicopters during H2S alerts, describe the types of H2S emergencies during which you consider the risk of helicopter activity to be acceptable and the precautions you will take during the flights;
(8) Procedures you will use to safely position all vessels attendant to the facility. Indicate where you will locate the vessels with respect to wind direction. Include the distance from the facility and what procedures you will use to safely relocate the vessels in an emergency;
(9) How you will provide protective-breathing equipment for all personnel, including contractors and visitors;
(10) The agencies and facilities you will notify in case of a release of H2S (that constitutes an emergency), how you will notify them, and their telephone numbers. Include all facilities that might be exposed to atmospheric concentrations of 20 ppm or more of H2S;
(11) The medical personnel and facilities you will use if needed, their addresses, and telephone numbers;
(12) H2S detector locations in production facilities producing gas containing 20 ppm or more of H2S. Include an “H2S Detector Location Drawing” showing:
(i) All vessels, flare outlets, wellheads, and other equipment handling production containing H2S;
(ii) Approximate maximum concentration of H2S in the gas stream; and
(iii) Location of all H2S sensors included in your contingency plan;
(13) Operational conditions when you expect to flare gas containing H2S including the estimated maximum gas flow rate, H2S concentration, and duration of flaring;
(14) Your assessment of the risks to personnel during flaring and what precautionary measures you will take;
(15) Primary and alternate methods to ignite the flare and procedures for sustaining ignition and monitoring the status of the flare (i.e., ignited or extinguished);
(16) Procedures to shut off the gas to the flare in the event the flare is extinguished;
(17) Portable or fixed sulphur dioxide (SO2)-detection system(s) you will use to determine SO2 concentration and exposure hazard when H2S is burned;
(18) Increased monitoring and warning procedures you will take when the SO2 concentration in the atmosphere reaches 2 ppm;
(19) Personnel protection measures or evacuation procedures you will initiate when the SO2 concentration in the atmosphere reaches 5 ppm;
(20) Engineering controls to protect personnel from SO2; and
(21) Any special equipment, procedures, or precautions you will use if you conduct any combination of drilling, well-completion, well-workover, and production operations simultaneously.
(g) Training program—(1) When and how often do employees need to be trained? All operators and contract personnel must complete an H2S training program to meet the requirements of this section:
(i) Before beginning work at the facility; and
(ii) Each year, within 1 year after completion of the previous class.
(2) What training documentation do I need? For each individual working on the platform, either:
(i) You must have documentation of this training at the facility where the individual is employed; or
(ii) The employee must carry a training completion card.
(3) What training do I need to give to visitors and employees previously trained on another facility?—(i) Trained employees or contractors transferred from another facility must attend a supplemental briefing on your H2S equipment and procedures before beginning duty at your facility;
(ii) Visitors who will remain on your facility more than 24 hours must receive the training required for employees by paragraph (g)(4) of this section; and
(iii) Visitors who will depart before spending 24 hours on the facility are exempt from the training required for employees, but they must, upon arrival, complete a briefing that includes:
(A) Information on the location and use of an assigned respirator; practice in donning and adjusting the assigned respirator; information on the safe briefing areas, alarm system, and hazards of H2S and SO2; and
(B) Instructions on their responsibilities in the event of an H2S release.
(4) What training must I provide to all other employees? You must train all individuals on your facility on the:
(i) Hazards of H2S and of SO2 and the provisions for personnel safety contained in the H2S Contingency Plan;
(ii) Proper use of safety equipment which the employee may be required to use;
(iii) Location of protective breathing equipment, H2S detectors and alarms, ventilation equipment, briefing areas, warning systems, evacuation procedures, and the direction of prevailing winds;
(iv) Restrictions and corrective measures concerning beards, spectacles, and contact lenses in conformance with ANSI Z88.2, American National Standard for Respiratory Protection (incorporated by reference as specified in § 250.198);
(v) Basic first-aid procedures applicable to victims of H2S exposure. During all drills and training sessions, you must address procedures for rescue and first aid for H2S victims;
(vi) Location of:
(A) The first-aid kit on the facility;
(B) Resuscitators; and
(C) Litter or other device on the facility.
(vii) Meaning of all warning signals.
(5) Do I need to post safety information? You must prominently post safety information on the facility and on vessels serving the facility (i.e., basic first-aid, escape routes, instructions for use of life boats, etc.).
(h) Drills. (1) When and how often do I need to conduct drills on H 2 S safety discussions on the facility? You must:
(i) Conduct a drill for each person at the facility during normal duty hours at least once every 7-day period. The drills must consist of a dry-run performance of personnel activities related to assigned jobs.
(ii) At a safety meeting or other meetings of all personnel, discuss drill performance, new H2S considerations at the facility, and other updated H2S information at least monthly.
(2) What documentation do I need? You must keep records of attendance for:
(i) Drilling, well-completion, and well-workover operations at the facility until operations are completed; and
(ii) Production operations at the facility or at the nearest field office for 1 year.
(i) Visual and audible warning systems—(1) How must I install wind direction equipment? You must install wind-direction equipment in a location visible at all times to individuals on or in the immediate vicinity of the facility.
(2) When do I need to display operational danger signs, display flags, or activate visual or audible alarms?—(i) You must display warning signs at all times on facilities with wells capable of producing H2S and on facilities that process gas containing H2S in concentrations of 20 ppm or more.
(ii) In addition to the signs, you must activate audible alarms and display flags or activate flashing red lights when atmospheric concentration of H2S reaches 20 ppm.
(3) What are the requirements for signs? Each sign must be a high-visibility yellow color with black lettering as follows:
Letter height | Wording
12 inches | Danger.
| Poisonous Gas.
| Hydrogen Sulfide.
7 inches | Do not approach if red flag is flying.
(Use appropriate wording at right) | Do not approach if red lights are flashing.
(4) May I use existing signs? You may use existing signs containing the words “Danger-Hydrogen Sulfide-H2S,” provided the words “Poisonous Gas. Do Not Approach if Red Flag is Flying” or “Red Lights are Flashing” in lettering of a minimum of 7 inches in height are displayed on a sign immediately adjacent to the existing sign.
(5) What are the requirements for flashing lights or flags? You must activate a sufficient number of lights or hoist a sufficient number of flags to be visible to vessels and aircraft. Each light must be of sufficient intensity to be seen by approaching vessels or aircraft any time it is activated (day or night). Each flag must be red, rectangular, a minimum width of 3 feet, and a minimum height of 2 feet.
(6) What is an audible warning system? An audible warning system is a public address system or siren, horn, or other similar warning device with a unique sound used only for H2S.
(7) Are there any other requirements for visual or audible warning devices? Yes, you must:
(i) Illuminate all signs and flags at night and under conditions of poor visibility; and
(ii) Use warning devices that are suitable for the electrical classification of the area.
(8) What actions must I take when the alarms are activated? When the warning devices are activated, the designated responsible persons must inform personnel of the level of danger and issue instructions on the initiation of appropriate protective measures.
(j) H 2 S-detection and H 2 S monitoring equipment—(1) What are the requirements for an H 2 S detection system? An H2S detection system must:
(i) Be capable of sensing a minimum of 10 ppm of H2S in the atmosphere; and
(ii) Activate audible and visual alarms when the concentration of H2S in the atmosphere reaches 20 ppm.
(2) Where must I have sensors for drilling, well-completion, and well-workover operations? You must locate sensors at the:
(i) Bell nipple;
(ii) Mud-return line receiver tank (possum belly);
(iii) Pipe-trip tank;
(iv) Shale shaker;
(v) Well-control fluid pit area;
(vi) Driller's station;
(vii) Living quarters; and
(viii) All other areas where H2S may accumulate.
(3) Do I need mud sensors? The District Manager may require mud sensors in the possum belly in cases where the ambient air sensors in the mud-return system do not consistently detect the presence of H2S.
(4) How often must I observe the sensors? During drilling, well-completion and well-workover operations, you must continuously observe the H2S levels indicated by the monitors in the work areas during the following operations:
(i) When you pull a wet string of drill pipe or workover string;
(ii) When circulating bottoms-up after a drilling break;
(iii) During cementing operations;
(iv) During logging operations; and
(v) When circulating to condition mud or other well-control fluid.
(5) Where must I have sensors for production operations? On a platform where gas containing H2S of 20 ppm or greater is produced, processed, or otherwise handled:
(i) You must have a sensor in rooms, buildings, deck areas, or low-laying deck areas not otherwise covered by paragraph (j)(2) of this section, where atmospheric concentrations of H2S could reach 20 ppm or more. You must have at least one sensor per 400 square feet of deck area or fractional part of 400 square feet;
(ii) You must have a sensor in buildings where personnel have their living quarters;
(iii) You must have a sensor within 10 feet of each vessel, compressor, wellhead, manifold, or pump, which could release enough H2S to result in atmospheric concentrations of 20 ppm at a distance of 10 feet from the component;
(iv) You may use one sensor to detect H2S around multiple pieces of equipment, provided the sensor is located no more than 10 feet from each piece, except that you need to use at least two sensors to monitor compressors exceeding 50 horsepower;
(v) You do not need to have sensors near wells that are shut in at the master valve and sealed closed;
(vi) When you determine where to place sensors, you must consider:
(A) The location of system fittings, flanges, valves, and other devices subject to leaks to the atmosphere; and
(B) Design factors, such as the type of decking and the location of fire walls; and
(vii) The District Manager may require additional sensors or other monitoring capabilities, if warranted by site specific conditions.
(6) How must I functionally test the H 2 S Detectors?—(i) Personnel trained to calibrate the particular H2S detector equipment being used must test detectors by exposing them to a known concentration in the range of 10 to 30 ppm of H2S.
(ii) If the results of any functional test are not within 2 ppm or 10 percent, whichever is greater, of the applied concentration, recalibrate the instrument.
(7) How often must I test my detectors?—(i) When conducting drilling, drill stem testing, well-completion, or well-workover operations in areas classified as H2S present or H2S unknown, test all detectors at least once every 24 hours. When drilling, begin functional testing before the bit is 1,500 feet (vertically) above the potential H2S zone.
(ii) When conducting production operations, test all detectors at least every 14 days between tests.
(iii) If equipment requires calibration as a result of two consecutive functional tests, the District Manager may require that H2S-detection and H2S-monitoring equipment be functionally tested and calibrated more frequently.
(8) What documentation must I keep?—(i) You must maintain records of testing and calibrations (in the drilling or production operations report, as applicable) at the facility to show the present status and history of each device, including dates and details concerning:
(A) Installation;
(B) Removal;
(C) Inspection;
(D) Repairs;
(E) Adjustments; and
(F) Reinstallation.
(ii) Records must be available for inspection by MMS personnel.
(9) What are the requirements for nearby vessels? If vessels are stationed overnight alongside facilities in areas of H2S present or H2S unknown, you must equip vessels with an H2S-detection system that activates audible and visual alarms when the concentration of H2S in the atmosphere reaches 20 ppm. This requirement does not apply to vessels positioned upwind and at a safe distance from the facility in accordance with the positioning procedure described in the approved H2S Contingency Plan.
(10) What are the requirements for nearby facilities? The District Manager may require you to equip nearby facilities with portable or fixed H2S detector(s) and to test and calibrate those detectors. To invoke this requirement, the District Manager will consider dispersion modeling results from a possible release to determine if 20 ppm H2S concentration levels could be exceeded at nearby facilities.
(11) What must I do to protect against SO 2 if I burn gas containing H 2 S? You must:
(i) Monitor the SO2 concentration in the air with portable or strategically placed fixed devices capable of detecting a minimum of 2 ppm of SO2;
(ii) Take readings at least hourly and at any time personnel detect SO2 odor or nasal irritation;
(iii) Implement the personnel protective measures specified in the H2S Contingency Plan if the SO2 concentration in the work area reaches 2 ppm; and
(iv) Calibrate devices every 3 months if you use fixed or portable electronic sensing devices to detect SO2.
(12) May I use alternative measures? You may follow alternative measures instead of those in paragraph (j)(11) of this section if you propose and the Regional Supervisor approves the alternative measures.
(13) What are the requirements for protective-breathing equipment? In an area classified as H2S present or H2S unknown, you must:
(i) Provide all personnel, including contractors and visitors on a facility, with immediate access to self-contained pressure-demand-type respirators with hoseline capability and breathing time of at least 15 minutes.
(ii) Design, select, use, and maintain respirators in conformance with ANSI Z88.2 (incorporated by reference as specified in § 250.198).
(iii) Make available at least two voice-transmission devices, which can be used while wearing a respirator, for use by designated personnel.
(iv) Make spectacle kits available as needed.
(v) Store protective-breathing equipment in a location that is quickly and easily accessible to all personnel.
(vi) Label all breathing-air bottles as containing breathing-quality air for human use.
(vii) Ensure that vessels attendant to facilities carry appropriate protective-breathing equipment for each crew member. The District Manager may require additional protective-breathing equipment on certain vessels attendant to the facility.
(viii) During H2S alerts, limit helicopter flights to and from facilities to the conditions specified in the H2S Contingency Plan. During authorized flights, the flight crew and passengers must use pressure-demand-type respirators. You must train all members of flight crews in the use of the particular type(s) of respirator equipment made available.
(ix) As appropriate to the particular operation(s), (production, drilling, well-completion or well-workover operations, or any combination of them), provide a system of breathing-air manifolds, hoses, and masks at the facility and the briefing areas. You must provide a cascade air-bottle system for the breathing-air manifolds to refill individual protective-breathing apparatus bottles. The cascade air-bottle system may be recharged by a high-pressure compressor suitable for providing breathing-quality air, provided the compressor suction is located in an uncontaminated atmosphere.
(k) Personnel safety equipment—(1) What additional personnel-safety equipment do I need? You must ensure that your facility has:
(i) Portable H2S detectors capable of detecting a 10 ppm concentration of H2S in the air available for use by all personnel;
(ii) Retrieval ropes with safety harnesses to retrieve incapacitated personnel from contaminated areas;
(iii) Chalkboards and/or note pads for communication purposes located on the rig floor, shale-shaker area, the cement-pump rooms, well-bay areas, production processing equipment area, gas compressor area, and pipeline-pump area;
(iv) Bull horns and flashing lights; and
(v) At least three resuscitators on manned facilities, and a number equal to the personnel on board, not to exceed three, on normally unmanned facilities, complete with face masks, oxygen bottles, and spare oxygen bottles.
(2) What are the requirements for ventilation equipment? You must:
(i) Use only explosion-proof ventilation devices;
(ii) Install ventilation devices in areas where H2S or SO2 may accumulate; and
(iii) Provide movable ventilation devices in work areas. The movable ventilation devices must be multidirectional and capable of dispersing H2S or SO2 vapors away from working personnel.
(3) What other personnel safety equipment do I need? You must have the following equipment readily available on each facility:
(i) A first-aid kit of appropriate size and content for the number of personnel on the facility; and
(ii) At least one litter or an equivalent device.
(l) Do I need to notify MMS in the event of an H 2 S release? You must notify MMS without delay in the event of a gas release which results in a 15-minute time-weighted average atmospheric concentration of H2S of 20 ppm or more anywhere on the OCS facility. You must report these gas releases to the District Manager immediately by oral communication, with a written follow-up report within 15 days, pursuant to §§ 250.188 through 250.190.
(m) Do I need to use special drilling, completion and workover fluids or procedures? When working in an area classified as H2S present or H2S unknown:
(1) You may use either water- or oil-base muds in accordance with § 250.300(b)(1).
(2) If you use water-base well-control fluids, and if ambient air sensors detect H2S, you must immediately conduct either the Garrett-Gas-Train test or a comparable test for soluble sulfides to confirm the presence of H2S.
(3) If the concentration detected by air sensors in over 20 ppm, personnel conducting the tests must don protective-breathing equipment conforming to paragraph (j)(13) of this section.
(4) You must maintain on the facility sufficient quantities of additives for the control of H2S, well-control fluid pH, and corrosion equipment.
(i) Scavengers. You must have scavengers for control of H2S available on the facility. When H2S is detected, you must add scavengers as needed. You must suspend drilling until the scavenger is circulated throughout the system.
(ii) Control pH. You must add additives for the control of pH to water-base well-control fluids in sufficient quantities to maintain pH of at least 10.0.
(iii) Corrosion inhibitors. You must add additives to the well-control fluid system as needed for the control of corrosion.
(5) You must degas well-control fluids containing H2S at the optimum location for the particular facility. You must collect the gases removed and burn them in a closed flare system conforming to paragraph (q)(6) of this section.
(n) What must I do in the event of a kick? In the event of a kick, you must use one of the following alternatives to dispose of the well-influx fluids giving consideration to personnel safety, possible environmental damage, and possible facility well-equipment damage:
(1) Contain the well-fluid influx by shutting in the well and pumping the fluids back into the formation.
(2) Control the kick by using appropriate well-control techniques to prevent formation fracturing in an open hole within the pressure limits of the well equipment (drill pipe, work string, casing, wellhead, BOP system, and related equipment). The disposal of H2S and other gases must be through pressurized or atmospheric mud-separator equipment depending on volume, pressure and concentration of H2S. The equipment must be designed to recover well-control fluids and burn the gases separated from the well-control fluid. The well-control fluid must be treated to neutralize H2S and restore and maintain the proper quality.
(o) Well testing in a zone known to contain H 2 S. When testing a well in a zone with H2S present, you must do all of the following:
(1) Before starting a well test, conduct safety meetings for all personnel who will be on the facility during the test. At the meetings, emphasize the use of protective-breathing equipment, first-aid procedures, and the Contingency Plan. Only competent personnel who are trained and are knowledgeable of the hazardous effects of H2S must be engaged in these tests.
(2) Perform well testing with the minimum number of personnel in the immediate vicinity of the rig floor and with the appropriate test equipment to safely and adequately perform the test. During the test, you must continuously monitor H2S levels.
(3) Not burn produced gases except through a flare which meets the requirements of paragraph (q)(6) of this section. Before flaring gas containing H2S, you must activate SO2 monitoring equipment in accordance with paragraph (j)(11) of this section. If you detect SO2 in excess of 2 ppm, you must implement the personnel protective measures in your H2S Contingency Plan, required by paragraph (f) of this section. You must also follow the requirements of § 250.1105. You must pipe gases from stored test fluids into the flare outlet and burn them.
(4) Use downhole test tools and wellhead equipment suitable for H2S service.
(5) Use tubulars suitable for H2S service. You must not use drill pipe for well testing without the prior approval of the District Manager. Water cushions must be thoroughly inhibited in order to prevent H2S attack on metals. You must flush the test string fluid treated for this purpose after completion of the test.
(6) Use surface test units and related equipment that is designed for H2S service.
(p) Metallurgical properties of equipment. When operating in a zone with H2S present, you must use equipment that is constructed of materials with metallurgical properties that resist or prevent sulfide stress cracking (also known as hydrogen embrittlement, stress corrosion cracking, or H2S embrittlement), chloride-stress cracking, hydrogen-induced cracking, and other failure modes. You must do all of the following:
(1) Use tubulars and other equipment, casing, tubing, drill pipe, couplings, flanges, and related equipment that is designed for H2S service.
(2) Use BOP system components, wellhead, pressure-control equipment, and related equipment exposed to H^2S-bearing fluids in conformance with NACE Standard MR0175-03 (incorporated by reference as specified in § 250.198).
(3) Use temporary downhole well-security devices such as retrievable packers and bridge plugs that are designed for H2S service.
(4) When producing in zones bearing H2S, use equipment constructed of materials capable of resisting or preventing sulfide stress cracking.
(5) Keep the use of welding to a minimum during the installation or modification of a production facility. Welding must be done in a manner that ensures resistance to sulfide stress cracking.
(q) General requirements when operating in an H 2 S zone—(1) Coring operations. When you conduct coring operations in H2S-bearing zones, all personnel in the working area must wear protective-breathing equipment at least 10 stands in advance of retrieving the core barrel. Cores to be transported must be sealed and marked for the presence of H2S.
(2) Logging operations. You must treat and condition well-control fluid in use for logging operations to minimize the effects of H2S on the logging equipment.
(3) Stripping operations. Personnel must monitor displaced well-control fluid returns and wear protective-breathing equipment in the working area when the atmospheric concentration of H2S reaches 20 ppm or if the well is under pressure.
(4) Gas-cut well-control fluid or well kick from H 2 S-bearing zone. If you decide to circulate out a kick, personnel in the working area during bottoms-up and extended-kill operations must wear protective-breathing equipment.
(5) Drill- and workover-string design and precautions. Drill- and workover-strings must be designed consistent with the anticipated depth, conditions of the hole, and reservoir environment to be encountered. You must minimize exposure of the drill- or workover-string to high stresses as much as practical and consistent with well conditions. Proper handling techniques must be taken to minimize notching and stress concentrations. Precautions must be taken to minimize stresses caused by doglegs, improper stiffness ratios, improper torque, whip, abrasive wear on tool joints, and joint imbalance.
(6) Flare system. The flare outlet must be of a diameter that allows easy nonrestricted flow of gas. You must locate flare line outlets on the downside of the facility and as far from the facility as is feasible, taking into account the prevailing wind directions, the wake effects caused by the facility and adjacent structure(s), and the height of all such facilities and structures. You must equip the flare outlet with an automatic ignition system including a pilot-light gas source or an equivalent system. You must have alternate methods for igniting the flare. You must pipe to the flare system used for H2S all vents from production process equipment, tanks, relief valves, burst plates, and similar devices.
(7) Corrosion mitigation. You must use effective means of monitoring and controlling corrosion caused by acid gases (H2S and CO2) in both the downhole and surface portions of a production system. You must take specific corrosion monitoring and mitigating measures in areas of unusually severe corrosion where accumulation of water and/or higher concentration of H2S exists.
(8) Wireline lubricators. Lubricators which may be exposed to fluids containing H2S must be of H2S-resistant materials.
(9) Fuel and/or instrument gas. You must not use gas containing H2S for instrument gas. You must not use gas containing H2S for fuel gas without the prior approval of the District Manager.
(10) Sensing lines and devices. Metals used for sensing line and safety-control devices which are necessarily exposed to H2S-bearing fluids must be constructed of H2S-corrosion resistant materials or coated so as to resist H2S corrosion.
(11) Elastomer seals. You must use H2S-resistant materials for all seals which may be exposed to fluids containing H2S.
(12) Water disposal. If you dispose of produced water by means other than subsurface injection, you must submit to the District Manager an analysis of the anticipated H2S content of the water at the final treatment vessel and at the discharge point. The District Manager may require that the water be treated for removal of H2S. The District Manager may require the submittal of an updated analysis if the water disposal rate or the potential H2S content increases.
(13) Deck drains. You must equip open deck drains with traps or similar devices to prevent the escape of H2S gas into the atmosphere.
(14) Sealed voids. You must take precautions to eliminate sealed spaces in piping designs (e.g., slip-on flanges, reinforcing pads) which can be invaded by atomic hydrogen when H2S is present.
[62 FR 3795, Jan. 27, 1997. Redesignated and amended at 63 FR 29479, 29485, May 29, 1998; 65 FR 15864, Mar. 24, 2000. Redesignated and amended at 68 FR 8423, 8434, Feb. 20, 2003; 71 FR 19645, Apr. 17, 2006; 72 FR 12096, Mar. 15, 2007; 72 FR 25201, May 4, 2007]

Subpart E—Oil and Gas Well-Completion Operations
§ 250.500
General requirements.
Well-completion operations shall be conducted in a manner to protect against harm or damage to life (including fish and other aquatic life), property, natural resources of the OCS including any mineral deposits (in areas leased and not leased), the national security or defense, or the marine, coastal, or human environment.
§ 250.501
Definition.
When used in this subpart, the following term shall have the meaning given below:
Well-completion operations means the work conducted to establish the production of a well after the production-casing string has been set, cemented, and pressure-tested.
§ 250.502
Equipment movement.
The movement of well-completion rigs and related equipment on and off a platform or from well to well on the same platform, including rigging up and rigging down, shall be conducted in a safe manner. All wells in the same well-bay which are capable of producing hydrocarbons shall be shut in below the surface with a pump-through-type tubing plug and at the surface with a closed master valve prior to moving well-completion rigs and related equipment, unless otherwise approved by the District Manager. A closed surface-controlled subsurface safety valve of the pump-through type may be used in lieu of the pump-through-type tubing plug, provided that the surface control has been locked out of operation. The well from which the rig or related equipment is to be moved shall also be equipped with a back-pressure valve prior to removing the blowout preventer (BOP) system and installing the tree.
[53 FR 10690, Apr. 1, 1988, as amended at 55 FR 47752, Nov. 15, 1990. Redesignated at 63 FR 29479, May 29, 1998]
§ 250.503
Emergency shutdown system.
When well-completion operations are conducted on a platform where there are other hydrocarbon-producing wells or other hydrocarbon flow, an emergency shutdown system (ESD) manually controlled station shall be installed near the driller's console or well-servicing unit operator's work station.
§ 250.504
Hydrogen sulfide.
When a well-completion operation is conducted in zones known to contain hydrogen sulfide (H2S) or in zones where the presence of H2S is unknown (as defined in § 250.490 of this part), the lessee shall take appropriate precautions to protect life and property on the platform or completion unit, including, but not limited to operations such as blowing the well down, dismantling wellhead equipment and flow lines, circulating the well, swabbing, and pulling tubing, pumps, and packers. The lessee shall comply with the requirements in § 250.490 of this part as well as the appropriate requirements of this subpart.
[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 29485, May 29, 1998; 68 FR 8434, Feb. 20, 2003]
§ 250.505
Subsea completions.
No subsea well completion shall be commenced until the lessee obtains written approval from the District Manager in accordance with § 250.513 of this part. That approval shall be based upon a case-by-case determination that the proposed equipment and procedures will adequately control the well and permit safe production operations.
[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 29485, May 29, 1998]
§ 250.506
Crew instructions.
Prior to engaging in well-completion operations, crew members shall be instructed in the safety requirements of the operations to be performed, possible hazards to be encountered, and general safety considerations to protect personnel, equipment, and the environment. Date and time of safety meetings shall be recorded and available at the facility for review by MMS representatives.
§§ 250.507-250.508
[Reserved]
§ 250.509
Well-completion structures on fixed platforms.
Derricks, masts, substructures, and related equipment shall be selected, designed, installed, used, and maintained so as to be adequate for the potential loads and conditions of loading that may be encountered during the proposed operations. Prior to moving a well-completion rig or equipment onto a platform, the lessee shall determine the structural capability of the platform to safely support the equipment and proposed operations, taking into consideration the corrosion protection, age of platform, and previous stresses to the platform.
[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50616, Dec. 8, 1989. Redesignated at 63 FR 29479, May 29, 1998]
§ 250.510
Diesel engine air intakes.
No later than May 31, 1989, diesel engine air intakes shall be equipped with a device to shut down the diesel engine in the event of runaway. Diesel engines which are continuously attended shall be equipped with either remote operated manual or automatic-shutdown devices. Diesel engines which are not continuously attended shall be equipped with automatic-shutdown devices.
§ 250.511
Traveling-block safety device.
After May 31, 1989, all units being used for well-completion operations which have both a traveling block and a crown block shall be equipped with a safety device which is designed to prevent the traveling block from striking the crown block. The device shall be checked for proper operation weekly and after each drill-line slipping operation. The results of the operational check shall be entered in the operations log.
§ 250.512
Field well-completion rules.
When geological and engineering information available in a field enables the District Manager to determine specific operating requirements, field well-completion rules may be established on the District Manager's initiative or in response to a request from a lessee. Such rules may modify the specific requirements of this subpart. After field well-completion rules have been established, well-completion operations in the field shall be conducted in accordance with such rules and other requirements of this subpart. Field well-completion rules may be amended or canceled for cause at any time upon the initiative of the District Manager or upon the request of a lessee.
§ 250.513
Approval and reporting of well-completion operations.
(a) No well-completion operation may begin until the lessee receives written approval from the District Manager. If completion is planned and the data are available at the time you submit the Application for Permit to Drill and Supplemental APD Information Sheet (Forms MMS-123 and MMS-123S), you may request approval for a well-completion on those forms (see §§ 250.410 through 250.418 of this part). If the District Manager has not approved the completion or if the completion objective or plans have significantly changed, you must submit an Application for Permit to Modify (Form MMS-124) for approval of such operations.
(b) You must submit the following with Form MMS-124 (or with Form MMS-123; Form MMS-123S):
(1) A brief description of the well-completion procedures to be followed, a statement of the expected surface pressure, and type and weight of completion fluids;
(2) A schematic drawing of the well showing the proposed producing zone(s) and the subsurface well-completion equipment to be used;
(3) For multiple completions, a partial electric log showing the zones proposed for completion, if logs have not been previously submitted;
(4) When the well-completion is in a zone known to contain H2S or a zone where the presence of H2S is unknown, information pursuant to § 250.490 of this part; and
(5) Payment of the service fee listed in § 250.125.
(c) Within 30 days after completion, you must submit to the District Manager an End of Operations Report (Form MMS-125), including a schematic of the tubing and subsurface equipment.
(d) You must submit public information copies of Form MMS-125 according to § 250.186.
[53 FR 10690, Apr. 1, 1988, as amended at 58 FR 49928, Sept. 24, 1993. Redesignated and amended at 63 FR 29479, 29485, May 29, 1998; 64 FR 72794, Dec. 28, 1999; 68 FR 8434, Feb. 20, 2003; 71 FR 19646, Apr. 17, 2006; 71 FR 40911, July 19, 2006; 72 FR 25201, May 4, 2007]
§ 250.514
Well-control fluids, equipment, and operations.
(a) Well-control fluids, equipment, and operations shall be designed, utilized, maintained, and/or tested as necessary to control the well in foreseeable conditions and circumstances, including subfreezing conditions. The well shall be continuously monitored during well-completion operations and shall not be left unattended at any time unless the well is shut in and secured.
(b) The following well-control-fluid equipment shall be installed, maintained, and utilized:
(1) A fill-up line above the uppermost BOP;
(2) A well-control, fluid-volume measuring device for determining fluid volumes when filling the hole on trips; and
(3) A recording mud-pit-level indicator to determine mud-pit-volume gains and losses. This indicator shall include both a visual and an audible warning device.
(c) When coming out of the hole with drill pipe, the annulus shall be filled with well-control fluid before the change in such fluid level decreases the hydrostatic pressure 75 pounds per square inch (psi) or every five stands of drill pipe, whichever gives a lower decrease in hydrostatic pressure. The number of stands of drill pipe and drill collars that may be pulled prior to filling the hole and the equivalent well-control fluid volume shall be calculated and posted near the operator's station. A mechanical, volumetric, or electronic device for measuring the amount of well-control fluid required to fill the hole shall be utilized.
§ 250.515
Blowout prevention equipment.
(a) The BOP system and system components and related well-control equipment shall be designed, used, maintained, and tested in a manner necessary to assure well control in foreseeable conditions and circumstances, including subfreezing conditions. The working pressure rating of the BOP system and BOP system components shall exceed the expected surface pressure to which they may be subjected. If the expected surface pressure exceeds the rated working pressure of the annular preventer, the lessee shall submit with Form MMS-124 or Form MMS-123, as appropriate, a well-control procedure that indicates how the annular preventer will be utilized, and the pressure limitations that will be applied during each mode of pressure control.
(b) The minimum BOP system for well-completion operations must meet the appropriate standards from the following table:
When | The minimum BOP stack must include
(1) The expected pressure is less than 5,000 psi | Three BOPs consisting of an annular, one set of pipe rams, and one set of blind or blind-shear rams.
(2) The expected pressure is 5,000 psi or greater or you use multiple tubing strings | Four BOPs consisting of an annular, two sets of pipe rams, and one set of blind or blind-shear rams.
(3) You handle multiple tubing strings simultaneously | Four BOPs consisting of an annular, one set of pipe rams, one set of dual pipe rams, and one set of blind or blind-shear rams.
(4) You use a tapered drill string | At least one set of pipe rams that are capable of sealing around each size of drill string. If the expected pressure is greater than 5,000 psi, then you must have at least two sets of pipe rams that are capable of sealing around the larger size drill string. You may substitute one set of variable bore rams for two sets of pipe rams.
(5) It is after February 21, 2006 | At least one set of blind-shear rams. The blind-shear rams must be capable of shearing the drill pipe or tubing in the hole.
(c) The BOP systems for well completions shall be equipped with the following:
(1) A hydraulic-actuating system that provides sufficient accumulator capacity to supply 1.5 times the volume necessary to close all BOP equipment units with a minimum pressure of 200 psi above the precharge pressure without assistance from a charging system. No later than December 1, 1988, accumulator regulators supplied by rig air and without a secondary source of pneumatic supply, shall be equipped with manual overrides, or alternately, other devices provided to ensure capability of hydraulic operations if rig air is lost.
(2) A secondary power source, independent from the primary power source, with sufficient capacity to close all BOP system components and hold them closed.
(3) Locking devices for the pipe-ram preventers.
(4) At least one remote BOP-control station and one BOP-control station on the rig floor.
(5) A choke line and a kill line each equipped with two full opening valves and a choke manifold. At least one of the valves on the choke line shall be remotely controlled. At least one of the valves on the kill line shall be remotely controlled, except that a check valve on the kill line in lieu of the remotely controlled valve may be installed provided that two readily accessible manual valves are in place and the check valve is placed between the manual valves and the pump. This equipment shall have a pressure rating at least equivalent to the ram preventers.
(d) An inside BOP or a spring-loaded, back-pressure safety valve and an essentially full-opening, work-string safety valve in the open position shall be maintained on the rig floor at all times during well-completion operations. A wrench to fit the work-string safety valve shall be readily available. Proper connections shall be readily available for inserting valves in the work string.
[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50616, Dec. 8, 1989; 58 FR 49928, Sept. 24, 1993. Redesignated at 62 29479, May 29, 1998, as amended at 68 FR 8434, Feb. 20, 2003]
§ 250.516
Blowout preventer system tests, inspections, and maintenance.
(a) BOP pressure testing timeframes. You must pressure test your BOP system:
(1) When installed; and
(2) Before 14 days have elapsed since your last BOP pressure test. You must begin to test your BOP system before 12 a.m. (midnight) on the 14th day following the conclusion of the previous test. However, the District Manager may require testing every 7 days if conditions or BOP performance warrant.
(b) BOP test pressures. When you test the BOP system, you must conduct a low pressure and a high pressure test for each BOP component. Each individual pressure test must hold pressure long enough to demonstrate that the tested component(s) holds the required pressure. The District Manager may approve or require other test pressures or practices. Required test pressures are as follows:
(1) All low pressure tests must be between 200 and 300 psi. Any initial pressure above 300 psi must be bled back to a pressure between 200 and 300 psi before starting the test. If the initial pressure exceeds 500 psi, you must bleed back to zero and reinitiate the test. You must conduct the low pressure test before the high pressure test.
(2) For ram-type BOP's, choke manifold, and other BOP equipment, the high pressure test must equal the rated working pressure of the equipment.
(3) For annular-type BOP's, the high pressure test must equal 70 percent of the rated working pressure of the equipment.
(c) Duration of pressure test. Each test must hold the required pressure for 5 minutes.
(1) For surface BOP systems and surface equipment of a subsea BOP system, a 3-minute test duration is acceptable if you record your test pressures on the outermost half of a 4-hour chart, on a 1-hour chart, or on a digital recorder.
(2) If the equipment does not hold the required pressure during a test, you must remedy the problem and retest the affected component(s).
(d) Additional BOP testing requirements. You must:
(1) Use water to test the surface BOP system;
(2) Stump test a subsurface BOP system before installation. You must use water to stump test a subsea BOP system. You may use drilling or completion fluids to conduct subsequent tests of a subsea BOP system;
(3) Alternate tests between control stations and pods. If a control station or pod is not functional, you must suspend further completion operations until that station or pod is operable;
(4) Pressure test the blind or blind-shear ram at least every 30 days;
(5) Function test annulars and rams every 7 days;
(6) Pressure-test variable bore-pipe rams against all sizes of pipe in use, excluding drill collars and bottom-hole tools; and
(7) Test affected BOP components following the disconnection or repair of any well-pressure containment seal in the wellhead or BOP stack assembly;
(e) Postponing BOP tests. You may postpone a BOP test if you have well-control problems. You must conduct the required BOP test as soon as possible (i.e., first trip out of the hole) after the problem has been remedied. You must record the reason for postponing any test in the driller's report.
(f) Weekly crew drills. You must conduct a weekly drill to familiarize all personnel engaged in well-completion operations with appropriate safety measures.
(g) BOP inspections. You must visually inspect your BOP system and marine riser at least once each day if weather and sea conditions permit. You may use television cameras to inspect this equipment. The District Manager may approve alternate methods and frequencies to inspect a marine riser.
(h) BOP maintenance. You must maintain your BOP system to ensure that the equipment functions properly.
(i) BOP test records. You must record the time, date, and results of all pressure tests, actuations, crew drills, and inspections of the BOP system, system components, and marine riser in the driller's report. In addition, you must:
(1) Record BOP test pressures on pressure charts;
(2) Have your onsite representative certify (sign and date) BOP test charts and reports as correct;
(3) Document the sequential order of BOP and auxiliary equipment testing and the pressure and duration of each test. You may reference a BOP test plan if it is available at the facility;
(4) Identify the control station or pod used during the test;
(5) Identify any problems or irregularities observed during BOP system and equipment testing and record actions taken to remedy the problems or irregularities;
(6) Retain all records including pressure charts, driller's report, and referenced documents pertaining to BOP tests, actuations, and inspections at the facility for the duration of the completion activity; and
(7) After completion of the well, you must retain all the records listed in paragraph (i)(6) of this section for a period of 2 years at the facility, at the lessee's field office nearest the OCS facility, or at another location conveniently available to the District Manager.
(j) Alternate methods. The District Manager may require, or approve, more frequent testing, as well as different test pressures and inspection methods, or other practices.
[63 FR 29607, June 1, 1998]
§ 250.517
Tubing and wellhead equipment.
(a) No tubing string shall be placed in service or continue to be used unless such tubing string has the necessary strength and pressure integrity and is otherwise suitable for its intended use.
(b) In the event of prolonged operations such as milling, fishing, jarring, or washing over that could damage the casing, the casing shall be pressure-tested, calipered, or otherwise evaluated every 30 days and the results submitted to the District Manager.
(c) When the tree is installed, the wellhead shall be equipped so that all annuli can be monitored for sustained pressure. If sustained casing pressure is observed on a well, the lessee shall immediately notify the District Manager.
(d) Wellhead, tree, and related equipment shall have a pressure rating greater than the shut-in tubing pressure and shall be designed, installed, used, maintained, and tested so as to achieve and maintain pressure control. New wells completed as flowing or gas-lift wells shall be equipped with a minimum of one master valve and one surface safety valve, installed above the master valve, in the vertical run of the tree.
(e) Subsurface safety equipment shall be installed, maintained, and tested in compliance with § 250.801 of this part.
[53 FR 10690, Apr. 1, 1988, as amended at 55 FR 47753 Nov. 15, 1990. Redesignated and amended at 63 FR 29479, 29485, May 29, 1998]

Subpart F—Oil and Gas Well-Workover Operations
§ 250.600
General requirements.
Well-workover operations shall be conducted in a manner to protect against harm or damage to life (including fish and other aquatic life), property, natural resources of the Outer Continental Shelf (OCS) including any mineral deposits (in areas leased and not leased), the national security or defense, or the marine, coastal, or human environment.
§ 250.601
Definitions.
When used in this subpart, the following terms shall have the meanings given below:
Expected surface pressure means the highest pressure predicted to be exerted upon the surface of a well. In calculating expected surface pressure, you must consider reservoir pressure as well as applied surface pressure.
Routine operations mean any of the following operations conducted on a well with the tree installed:
(a) Cutting paraffin;
(b) Removing and setting pump-through-type tubing plugs, gas-lift valves, and subsurface safety valves which can be removed by wireline operations;
(c) Bailing sand;
(d) Pressure surveys;
(e) Swabbing;
(f) Scale or corrosion treatment;
(g) Caliper and gauge surveys;
(h) Corrosion inhibitor treatment;
(i) Removing or replacing subsurface pumps;
(j) Through-tubing logging (diagnostics);
(k) Wireline fishing; and
(l) Setting and retrieving other subsurface flow-control devices.
Workover operations mean the work conducted on wells after the initial completion for the purpose of maintaining or restoring the productivity of a well.
[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998, as amended at 71 FR 11313, Mar. 7, 2006]
§ 250.602
Equipment movement.
The movement of well-workover rigs and related equipment on and off a platform or from well to well on the same platform, including rigging up and rigging down, shall be conducted in a safe manner. All wells in the same well-bay which are capable of producing hydrocarbons shall be shut in below the surface with a pump-through-type tubing plug and at the surface with a closed master valve prior to moving well-workover rigs and related equipment unless otherwise approved by the District Manager. A closed surface-controlled subsurface safety valve of the pump-through-type may be used in lieu of the pump-through-type tubing plug provided that the surface control has been locked out of operation. The well to which a well-workover rig or related equipment is to be moved shall also be equipped with a back-pressure valve prior to removing the tree and installing and testing the blowout-preventer (BOP) system. The well from which a well-workover rig or related equipment is to be moved shall also be equipped with a back pressure valve prior to removing the BOP system and installing the tree. Coiled tubing units, snubbing units, or wireline units may be moved onto a platform without shutting in wells.
§ 250.603
Emergency shutdown system.
When well-workover operations are conducted on a well with the tree removed, an emergency shutdown system (ESD) manually controlled station shall be installed near the driller's console or well-servicing unit operator's work station, except when there is no other hydrocarbon-producing well or other hydrocarbon flow on the platform.
§ 250.604
Hydrogen sulfide.
When a well-workover operation is conducted in zones known to contain hydrogen sulfide (H2S) or in zones where the presence of H2S is unknown (as defined in § 250.490 of this part), the lessee shall take appropriate precautions to protect life and property on the platform or rig, including but not limited to operations such as blowing the well down, dismantling wellhead equipment and flow lines, circulating the well, swabbing, and pulling tubing, pumps and packers. The lessee shall comply with the requirements in § 250.490 of this part as well as the appropriate requirements of this subpart.
[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 29485, May 29, 1998; 64 FR 9065, Feb. 24, 1999; 68 FR 8435, Feb. 20, 2003]
§ 250.605
Subsea workovers.
No subsea well-workover operation including routine operations shall be commenced until the lessee obtains written approval from the District Manager in accordance with § 250.613 of this part. That approval shall be based upon a case-by-case determination that the proposed equipment and procedures will maintain adequate control of the well and permit continued safe production operations.
[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 29485, May 29, 1998]
§ 250.606
Crew instructions.
Prior to engaging in well-workover operations, crew members shall be instructed in the safety requirements of the operations to be performed, possible hazards to be encountered, and general safety considerations to protect personnel, equipment, and the environment. Date and time of safety meetings shall be recorded and available at the facility for review by a Minerals Management Service representative.
§§ 250.607-250.608
[Reserved]
§ 250.609
Well-workover structures on fixed platforms.
Derricks, masts, substructures, and related equipment shall be selected, designed, installed, used, and maintained so as to be adequate for the potential loads and conditions of loading that may be encountered during the operations proposed. Prior to moving a well-workover rig or well-servicing equipment onto a platform, the lessee shall determine the structural capability of the platform to safely support the equipment and proposed operations, taking into consideration the corrosion protection, age of the platform, and previous stresses to the platform.
§ 250.610
Diesel engine air intakes.
No later than May 31, 1989, diesel engine air intakes shall be equipped with a device to shut down the diesel engine in the event of runaway. Diesel engines which are continuously attended shall be equipped with either remote operated manual or automatic shutdown devices. Diesel engines which are not continuously attended shall be equipped with automatic shutdown devices.
[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50616, Dec. 8, 1989. Redesignated at 63 FR 29479, May 29, 1998]
§ 250.611
Traveling-block safety device.
After May 31, 1989, all units being used for well-workover operations which have both a traveling block and a crown block shall be equipped with a safety device which is designed to prevent the traveling block from striking the crown block. The device shall be checked for proper operation weekly and after each drill-line slipping operation. The results of the operational check shall be entered in the operations log.
§ 250.612
Field well-workover rules.
When geological and engineering information available in a field enables the District Manager to determine specific operating requirements, field well-workover rules may be established on the District Manager's initiative or in response to a request from a lessee. Such rules may modify the specific requirements of this subpart. After field well-workover rules have been established, well-workover operations in the field shall be conducted in accordance with such rules and other requirements of this subpart. Field well-workover rules may be amended or canceled for cause at any time upon the initiative of the District Manager or upon the request of a lessee.
§ 250.613
Approval and reporting for well-workover operations.
(a) No well-workover operation except routine ones, as defined in § 250.601 of this part, shall begin until the lessee receives written approval from the District Manager. Approval for these operations must be requested on Form MMS-124, Application for Permit to Modify.
(b) You must submit the following with Form MMS-124:
(1) A brief description of the well-workover procedures to be followed, a statement of the expected surface pressure, and type and weight of workover fluids;
(2) When changes in existing subsurface equipment are proposed, a schematic drawing of the well showing the zone proposed for workover and the workover equipment to be used;
(3) Where the well-workover is in a zone known to contain H2S or a zone where the presence of H2S is unknown, information pursuant to § 250.490 of this part; and
(4) Payment of the service fee listed in § 250.125.
(c) The following additional information shall be submitted with Form MMS-124 if completing to a new zone is proposed:
(1) Reason for abandonment of present producing zone including supportive well test data, and
(2) A statement of anticipated or known pressure data for the new zone.
(d) Within 30 days after completing the well-workover operation, except routine operations, Form MMS-124, Application for Permit to Modify, shall be submitted to the District Manager, showing the work as performed. In the case of a well-workover operation resulting in the initial recompletion of a well into a new zone, a Form MMS-125, End of Operations Report, shall be submitted to the District Manager and shall include a new schematic of the tubing subsurface equipment if any subsurface equipment has been changed.
[53 FR 10690, Apr. 1, 1988, as amended at 58 FR 49928, Sept. 24, 1993. Redesignated and amended at 63 FR 29479, 29485, May 29, 1998; 65 FR 35824, June 6, 2000; 68 FR 8435, Feb. 20, 2003; 71 FR 40912, July 19, 2006; 72 FR 25201, May 4, 2007]
§ 250.614
Well-control fluids, equipment, and operations.
The following requirements apply during all well-workover operations with the tree removed:
(a) Well-control fluids, equipment, and operations shall be designed, utilized, maintained, and/or tested as necessary to control the well in foreseeable conditions and circumstances, including subfreezing conditions. The well shall be continuously monitored during well-workover operations and shall not be left unattended at anytime unless the well is shut in and secured.
(b) When coming out of the hole with drill pipe or a workover string, the annulus shall be filled with well-control fluid before the change in such fluid level decreases the hydrostatic pressure 75 pounds per square inch (psi) or every five stands of drill pipe or workover string, whichever gives a lower decrease in hydrostatic pressure. The number of stands of drill pipe or workover string and drill collars that may be pulled prior to filling the hole and the equivalent well-control fluid volume shall be calculated and posted near the operator's station. A mechanical, volumetric, or electronic device for measuring the amount of well-control fluid required to fill the hold shall be utilized.
(c) The following well-control-fluid equipment shall be installed, maintained, and utilized:
(1) A fill-up line above the uppermost BOP;
(2) A well-control, fluid-volume measuring device for determining fluid volumes when filling the hole on trips; and
(3) A recording mud-pit-level indicator to determine mud-pit-volume gains and losses. This indicator shall include both a visual and an audible warning device.
§ 250.615
Blowout prevention equipment.
(a) The BOP system, system components and related well-control equipment shall be designed, used, maintained, and tested in a manner necessary to assure well control in foreseeable conditions and circumstances, including subfreezing conditions. The working pressure rating of the BOP system and system components shall exceed the expected surface pressure to which they may be subjected. If the expected surface pressure exceeds the rated working pressure of the annular preventer, the lessee shall submit with Form MMS-124, requesting approval of the well-workover operation, a well-control procedure that indicates how the annular preventer will be utilized, and the pressure limitations that will be applied during each mode of pressure control.
(b) The minimum BOP system for well-workover operations with the tree removed must meet the appropriate standards from the following table:
When | The minimum BOP stack must include
(1) The expected pressure is less than 5,000 psi | Three BOPs consisting of an annular, one set of pipe rams, and one set of blind or blind-shear rams.
(2) The expected pressure is 5,000 psi or greater or you use multiple tubing strings | Four BOPs consisting of an annular, two sets of pipe rams, and one set of blind or blind-shear rams.
| (3) You handle multiple tubing strings simultaneously | Four BOPs consisting of an annular, one set of pipe rams, one set of dual pipe rams, and one set of blind or blind-shear rams.
(4) You use a tapered drill string | At least one set of pipe rams that are capable of sealing around each size of drill string. If the expected pressure is greater than 5,000 psi, then you must have at least two sets of pipe rams that are capable of sealing around the larger size drill string. You may substitute one set of variable bore rams for two sets of pipe rams.
(5) It is after February 21, 2006 | At least one set of blind-shear rams. The blind-shear rams must be capable of shearing the drill pipe or tubing in the hole.
(c) The BOP systems for well-workover operations with the tree removed shall be equipped with the following:
(1) A hydraulic-actuating system that provides sufficient accumulator capacity to supply 1.5 times the volume necessary to close all BOP equipment units with a minimum pressure of 200 psi above the precharge pressure without assistance from a charging system. No later than December 1, 1988, accumulator regulators supplied by rig air and without a secondary source of pneumatic supply, shall be equipped with manual overrides, or alternately, other devices provided to ensure capability of hydraulic operations if rig air is lost;
(2) A secondary power source, independent from the primary power source, with sufficient capacity to close all BOP system components and hold them closed;
(3) Locking devices for the pipe-ram preventers;
(4) At least one remote BOP-control station and one BOP-control station on the rig floor; and
(5) A choke line and a kill line each equipped with two full opening valves and a choke manifold. At least one of the valves on the choke-line shall be remotely controlled. At least one of the valves on the kill line shall be remotely controlled, except that a check valve on the kill line in lieu of the remotely controlled valve may be installed provided two readily accessible manual valves are in place and the check valve is placed between the manual valves and the pump. This equipment shall have a pressure rating at least equivalent to the ram preventers.
(d) The minimum BOP-system components for well-workover operations with the tree in place and performed through the wellhead inside of conventional tubing using small-diameter jointed pipe (usually 3/4 inch to 11/4 inch) as a work string, i.e., small-tubing operations, shall include the following:
(1) Two sets of pipe rams, and
(2) One set of blind rams.
(e) For coiled tubing operations with the production tree in place, you must meet the following minimum requirements for the BOP system:
(1) BOP system components must be in the following order from the top down:
BOP system when expected surface pressures are less than or equal to 3,500 psi | BOP system when expected surface pressures are greater than 3,500 psi | BOP system for wells with returns taken through an outlet on the BOP stack
Stripper or annular-type well control component | Stripper or annular-type well control component | Stripper or annular-type well control component.
Hydraulically-operated blind rams | Hydraulically-operated blind rams | Hydraulically-operated blind rams.
Hydraulically-operated shear rams | Hydraulically-operated shear rams | Hydraulically-operated shear rams.
Kill line inlet | Kill line inlet | Kill line inlet.
Hydraulically-operated two-way slip rams | Hydraulically-operated two-way slip rams | Hydraulically-operated two-way slip rams. Hydraulically-operated pipe rams.
Hydraulically-operated pipe rams | Hydraulically-operated pipe rams. Hydraulically-operated blind-shear rams. These rams should be located as close to the tree as practical | A flow tee or cross. Hydraulically-operated pipe rams. Hydraulically-operated blind-shear rams on wells with surface pressures >3,500 psi. As an option, the pipe rams can be placed below the blind-shear rams. The blind-shear rams should be located as close to the tree as practical.
(2) You may use a set of hydraulically-operated combination rams for the blind rams and shear rams.
(3) You may use a set of hydraulically-operated combination rams for the hydraulic two-way slip rams and the hydraulically-operated pipe rams.
(4) You must attach a dual check valve assembly to the coiled tubing connector at the downhole end of the coiled tubing string for all coiled tubing well-workover operations. If you plan to conduct operations without downhole check valves, you must describe alternate procedures and equipment in Form MMS-124, Application for Permit to Modify and have it approved by the District Manager.
(5) You must have a kill line and a separate choke line. You must equip each line with two full-opening valves and at least one of the valves must be remotely controlled. You may use a manual valve instead of the remotely controlled valve on the kill line if you install a check valve between the two full-opening manual valves and the pump or manifold. The valves must have a working pressure rating equal to or greater than the working pressure rating of the connection to which they are attached, and you must install them between the well control stack and the choke or kill line. For operations with expected surface pressures greater than 3,500 psi, the kill line must be connected to a pump or manifold. You must not use the kill line inlet on the BOP stack for taking fluid returns from the wellbore.
(6) You must have a hydraulic-actuating system that provides sufficient accumulator capacity to close-open-close each component in the BOP stack. This cycle must be completed with at least 200 psi above the pre-charge pressure, without assistance from a charging system.
(7) All connections used in the surface BOP system from the tree to the uppermost required ram must be flanged, including the connections between the well control stack and the first full-opening valve on the choke line and the kill line.
(f) The minimum BOP-system components for well-workover operations with the tree in place and performed by moving tubing or drill pipe in or out of a well under pressure utilizing equipment specifically designed for that purpose, i.e., snubbing operations, shall include the following:
(1) One set of pipe rams hydraulically operated, and
(2) Two sets of stripper-type pipe rams hydraulically operated with spacer spool.
(g) An inside BOP or a spring-loaded, back-pressure safety valve and an essentially full-opening, work-string safety valve in the open position shall be maintained on the rig floor at all times during well-workover operations when the tree is removed or during well-workover operations with the tree installed and using small tubing as the work string. A wrench to fit the work-string safety valve shall be readily available. Proper connections shall be readily available for inserting valves in the work string. The full-opening safety valve is not required for coiled tubing or snubbing operations.
[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50616, Dec. 8, 1989; 58 FR 49928, Sept. 24, 1993. Redesignated at 63 FR 29479, May 29, 1998, as amended at 68 FR 8435, Feb. 20, 2003; 71 FR 11313, Mar. 7, 2006; 71 FR 29710, May 23, 2006]
§ 250.616
Blowout preventer system testing, records, and drills.
(a) BOP pressure tests. When you pressure test the BOP system you must conduct a low-pressure test and a high-pressure test for each component. You must conduct the low-pressure test before the high-pressure test. For purposes of this section, BOP system components include ram-type BOP's, related control equipment, choke and kill lines, and valves, manifolds, strippers, and safety valves. Surface BOP systems must be pressure tested with water.
(1) Low pressure tests. All BOP system components must be successfully tested to a low pressure between 200 and 300 psi. Any initial pressure equal to or greater than 300 psi must be bled back to a pressure between 200 and 300 psi before starting the test. If the initial pressure exceeds 500 psi, you must bleed back to zero before starting the test.
(2) High pressure tests. All BOP system components must be successfully tested to the rated working pressure of the BOP equipment, or as otherwise approved by the District Manager. The annular-type BOP must be successfully tested at 70 percent of its rated working pressure or as otherwise approved by the District Manager.
(3) Other testing requirements. Variable bore pipe rams must be pressure tested against the largest and smallest sizes of tubulars in use (jointed pipe, seamless pipe) in the well.
(b) The BOP systems shall be tested at the following times:
(1) When installed;
(2) At least every 7 days, alternating between control stations and at staggered intervals to allow each crew to operate the equipment. If either control system is not functional, further operations shall be suspended until the nonfunctional, system is operable. The test every 7 days is not required for blind or blind-shear rams. The blind or blind-shear rams shall be tested at least once every 30 days during operation. A longer period between blowout preventer tests is allowed when there is a stuck pipe or pressure-control operation and remedial efforts are being performed. The tests shall be conducted as soon as possible and before normal operations resume. The reason for postponing testing shall be entered into the operations log.
(3) Following repairs that require disconnecting a pressure seal in the assembly, the affected seal will be pressure tested.
(c) All personnel engaged in well-workover operations shall participate in a weekly BOP drill to familiarize crew members with appropriate safety measures.
(d) You may conduct a stump test for the BOP system on location. A plan describing the stump test procedures must be included in your Form MMS-124, Application for Permit to Modify, and must be approved by the District Manager.
(e) You must test the coiled tubing connector to a low pressure of 200 to 300 psi, followed by a high pressure test to the rated working pressure of the connector or the expected surface pressure, whichever is less. You must successfully pressure test the dual check valves to the rated working pressure of the connector, the rated working pressure of the dual check valve, expected surface pressure, or the collapse pressure of the coiled tubing, whichever is less.
(f) You must record test pressures during BOP and coiled tubing tests on a pressure chart, or with a digital recorder, unless otherwise approved by the District Manager. The test interval for each BOP system component must be 5 minutes, except for coiled tubing operations, which must include a 10 minute high-pressure test for the coiled tubing string. Your representative at the facility must certify that the charts are correct.
(g) The time, date, and results of all pressure tests, actuations, inspections, and crew drills of the BOP system, system components, and marine risers shall be recorded in the operations log. The BOP tests shall be documented in accordance with the following:
(1) The documentation shall indicate the sequential order of BOP and auxiliary equipment testing and the pressure and duration of each test. As an alternate, the documentation in the operations log may reference a BOP test plan that contains the required information and is retained on file at the facility.
(2) The control station used during the test shall be identified in the operations log. For a subsea system, the pod used during the test shall be identified in the operations log.
(3) Any problems or irregularities observed during BOP and auxiliary equipment testing and any actions taken to remedy such problems or irregularities shall be noted in the operations log.
(4) Documentation required to be entered in the operation log may instead be referenced in the operations log. All records including pressure charts, operations log, and referenced documents pertaining to BOP tests, actuations, and inspections, shall be available for MMS review at the facility for the duration of well-workover activity. Following completion of the well-workover activity, all such records shall be retained for a period of 2 years at the facility, at the lessee's filed office nearest the OCS facility, or at another location conveniently available to the District Manager.
[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1989; 56 FR 1915, Jan. 18, 1991. Redesignated at 63 FR 29479, May 29, 1998; 71 FR 11313, Mar. 7, 2006]
§ 250.617
Tubing and wellhead equipment.
The lessee shall comply with the following requirements during well-workover operations with the tree removed:
(a) No tubing string shall be placed in service or continue to be used unless such tubing string has the necessary strength and pressure integrity and is otherwise suitable for its intended use.
(b) In the event of prolonged operations such as milling, fishing, jarring, or washing over that could damage the casing, the casing shall be pressure tested, calipered, or otherwise evaluated every 30 days and the results submitted to the District Manager.
(c) When reinstalling the tree, the wellhead shall be equipped so that all annuli can be monitored for sustained pressure. If sustained casing pressure is observed on a well, the lessee shall immediately notify the District Manager.
(d) Wellhead, tree, and related equipment shall have a pressure rating greater than the shut-in tubing pressure and shall be designed, installed, used, maintained, and tested so as to achieve and maintain pressure control. The tree shall be equipped with a minimum of one master valve and one surface safety valve in the vertical run of the tree when it is reinstalled.
(e) Subsurface safety equipment shall be installed, maintained, and tested in compliance with § 250.801 of this part.
[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1989; 55 FR 47753, Nov. 15, 1990. Redesignated and amended at 63 FR 29479, 29485, May 29, 1998]
§ 250.618
Wireline operations.
The lessee shall comply with the following requirements during routine, as defined in § 250.601 of this part, and nonroutine wireline workover operations:
(a) Wireline operations shall be conducted so as to minimize leakage of well fluids. Any leakage that does occur shall be contained to prevent pollution.
(b) All wireline perforating operations and all other wireline operations where communication exists between the completed hydrocarbon-bearing zone(s) and the wellbore shall use a lubricator assembly containing at least one wireline valve.
(c) When the lubricator is initially installed on the well, it shall be successfully pressure tested to the expected shut-in surface pressure.
[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 29485, May 29, 1998]
Subpart G [Reserved]

Subpart H—Oil and Gas Production Safety Systems
§ 250.800
General requirements.
(a) Production safety equipment shall be designed, installed, used, maintained, and tested in a manner to assure the safety and protection of the human, marine, and coastal environments. Production safety systems operated in subfreezing climates shall utilize equipment and procedures selected with consideration of floating ice, icing, and other extreme environmental conditions that may occur in the area. Production shall not commence until the production safety system has been approved and a preproduction inspection has been requested by the lessee.
(b) For all new floating production systems (FPSs) (e.g., column-stabilized-units (CSUs); floating production, storage and offloading facilities (FPSOs); tension-leg platforms (TLPs); spars, etc.), you must do all of the following:
(1) Comply with API RP 14J (incorporated by reference as specified in 30 CFR 250.198);
(2) Meet the drilling and production riser standards of API RP 2RD (incorporated by reference as specified in 30 CFR 250.198);
(3) Design all stationkeeping systems for floating facilities to meet the standards of API RP 2SK (incorporated by reference as specified in 30 CFR 250.198), as well as relevant U.S. Coast Guard regulations; and
(4) Design stationkeeping systems for floating facilities to meet structural requirements in subpart I, §§ 250.900 through 250.921 of this part.
[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998, as amended at 70 FR 41574, July 19, 2005]
§ 250.801
Subsurface safety devices.
(a) General. All tubing installations open to hydrocarbon-bearing zones shall be equipped with subsurface safety devices that will shut off the flow from the well in the event of an emergency unless, after application and justification, the well is determined by the District Manager to be incapable of natural flowing. These devices may consist of a surface-controlled subsurface safety valve (SSSV), a subsurface-controlled SSSV, an injection valve, a tubing plug, or a tubing/annular subsurface safety device, and any associated safety valve lock or landing nipple.
(b) Specifications for SSSV's. Surface-controlled and subsurface-controlled SSSV's and safety valve locks and landing nipples installed in the OCS shall conform to the requirements in § 250.806 of this part.
(c) Surface-controlled SSSV's. All tubing installations open to a hydrocarbon-bearing zone which is capable of natural flow shall be equipped with a surface-controlled SSSV, except as specified in paragraphs (d), (f), and (g) of this section. The surface controls may be located on the site or a remote location. Wells not previously equipped with a surface-controlled SSSV and wells in which a surface-controlled SSSV has been replaced with a subsurface-controlled SSSV in accordance with paragraph (d)(2) of this section shall be equipped with a surface-controlled SSSV when the tubing is first removed and reinstalled.
(d) Subsurface-controlled SSSV's. Wells may be equipped with subsurface-controlled SSSV's in lieu of a surface-controlled SSSV provided the lessee demonstrates to the District Manager's satisfaction that one of the following criteria are met:
(1) Wells not previously equipped with surface-controlled SSSV's shall be so equipped when the tubing is first removed and reinstalled,
(2) The subsurface-controlled SSSV is installed in wells completed from a single-well or multiwell satellite caisson or seafloor completions, or
(3) The subsurface-controlled SSSV is installed in wells with a surface-controlled SSSV that has become inoperable and cannot be repaired without removal and reinstallation of the tubing.
(e) Design, installation, and operation of SSSV's. The SSSV's shall be designed, installed, operated, and maintained to ensure reliable operation.
(1) The device shall be installed at a depth of 100 feet or more below the seafloor within 2 days after production is established. When warranted by conditions such as permafrost, unstable bottom conditions, hydrate formation, or paraffins, an alternate setting depth of the subsurface safety device may be approved by the District Manager.
(2) Until a subsurface safety device is installed, the well shall be attended in the immediate vicinity so that emergency actions may be taken while the well is open to flow. During testing and inspection procedures, the well shall not be left unattended while open to production unless a properly operating subsurface-safety device has been installed in the well.
(3) The well shall not be open to flow while the subsurface safety device is removed, except when flowing of the well is necessary for a particular operation such as cutting paraffin, bailing sand, or similar operations.
(4) All SSSV's must be inspected, installed, maintained, and tested in accordance with American Petroleum Institute Recommended Practice 14B, Recommended Practice for Design, Installation, Repair, and Operation of Subsurface Safety Valve Systems (incorporated by reference as specified in § 250.198).
(f) Subsurface safety devices in shut-in wells. New completions (perforated but not placed on production) and completions shut in for a period of 6 months shall be equipped with either (1) a pump-through-type tubing plug; (2) a surface-controlled SSSV, provided the surface control has been rendered inoperative; or (3) an injection valve capable of preventing backflow. The setting depth of the subsurface safety device shall be approved by the District Manager on a case-by-case basis, when warranted by conditions such as permafrost, unstable bottom conditions, hydrate formations, and paraffins.
(g) Subsurface safety devices in injection wells. A surface-controlled SSSV or an injection valve capable of preventing backflow shall be installed in all injection wells. This requirement is not applicable if the District Manager concurs that the well is incapable of flowing. The lessee shall verify the no-flow condition of the well annually.
(h) Temporary removal for routine operations. (1) Each wireline- or pumpdown-retrievable subsurface safety device may be removed, without further authorization or notice, for a routine operation which does not require the approval of a Form MMS-124, Application for Permit to Modify, in § 250.601 of this part for a period not to exceed 15 days.
(2) The well shall be identified by a sign on the wellhead stating that the subsurface safety device has been removed. The removal of the subsurface safety device shall be noted in the records as required in § 250.804(b) of this part. If the master valve is open, a trained person shall be in the immediate vicinity of the well to attend the well so that emergency actions may be taken, if necessary.
(3) A platform well shall be monitored, but a person need not remain in the well-bay area continuously if the master valve is closed. If the well is on a satellite structure, it must be attended or a pump-through plug installed in the tubing at least 100 feet below the mud line and the master valve closed, unless otherwise approved by the District Manager.
(4) The well shall not be allowed to flow while the subsurface safety device is removed, except when flowing the well is necessary for that particular operation. The provisions of this paragraph are not applicable to the testing and inspection procedures in § 250.804 of this part.
(i) Additional safety equipment. All tubing installations in which a wireline- or pumpdown-retrievable subsurface safety device is installed after the effective date of this subpart shall be equipped with a landing nipple with flow couplings or other protective equipment above and below to provide for the setting of the SSSV. The control system for all surface-controlled SSSV's shall be an integral part of the platform Emergency Shutdown System (ESD). In addition to the activation of the ESD by manual action on the platform, the system may be activated by a signal from a remote location. Surface-controlled SSSV's shall close in response to shut-in signals from the ESD and in response to the fire loop or other fire detection devices.
(j) Emergency action. In the event of an emergency, such as an impending storm, any well not equipped with a subsurface safety device and which is capable of natural flow shall have the device properly installed as soon as possible with due consideration being given to personnel safety.
[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1989; 58 FR 49928, Sept. 24, 1993. Redesignated and amended at 63 FR 29479, 29485, May 29, 1998; 72 FR 12096, Mar. 15, 2007; 72 FR 25201, May 4, 2007]
§ 250.802
Design, installation, and operation of surface production-safety systems.
(a) General. All production facilities, including separators, treaters, compressors, headers, and flowlines shall be designed, installed, and maintained in a manner which provides for efficiency, safety of operation, and protection of the environment.
(b) Platforms. You must protect all platform production facilities with a basic and ancillary surface safety system designed, analyzed, installed, tested, and maintained in operating condition in accordance with API RP 14C (incorporated by reference as specified in § 250.198). If you use processing components other than those for which Safety Analysis Checklists are included in API RP 14C you must utilize the analysis technique and documentation specified therein to determine the effects and requirements of these components on the safety system. Safety device requirements for pipelines are under § 250.1004.
(c) Specification for surface safety valves (SSV) and underwater safety valves (USV). All wellhead SSV's, USV's, and their actuators which are installed in the OCS shall conform to the requirements in § 250.806 of this part.
(d) Use of SSV's and USV's. All SSVs and USVs must be inspected, installed, maintained, and tested in accordance with API RP 14H, Recommended Practice for Installation, Maintenance, and Repair of Surface Safety Valves and Underwater Safety Valves Offshore (incorporated by reference as specified in § 250.198). If any SSV or USV does not operate properly or if any fluid flow is observed during the leakage test, the valve shall be repaired or replaced.
(e) Approval of safety-systems design and installation features. Prior to installation, the lessee shall submit, in duplicate for approval to the District Manager a production safety system application containing information relative to design and installation features. Information concerning approved design and installation features shall be maintained by the lessee at the lessee's offshore field office nearest the OCS facility or other location conveniently available to the District Manager. All approvals are subject to field verifications. The application shall include the following:
(1) A schematic flow diagram showing tubing pressure, size, capacity, design working pressure of separators, flare scrubbers, treaters, storage tanks, compressors, pipeline pumps, metering devices, and other hydrocarbon-handling vessels.
(2) A schematic piping flow diagram (API RP 14C, Figure E, incorporated by reference as specified in § 250.198) and the related Safety analysis Function Evaluation chart (API RP 14C, subsection 4.3c, incorporated by reference as specified in § 250.198).
(3) A schematic piping diagram showing the size and maximum allowable working pressures as determined in accordance with API RP 14E, Design and Installation of Offshore Production Platform Piping Systems (incorporated by reference as specified in § 250.198).
(4) Electrical system information including the following:
(i) A plan for each platform deck outlining all hazardous areas classified according to API RP 500, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Division 1 and Division 2, or API RP 505, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Zone 0, Zone 1, and Zone 2 (incorporated by reference as specified in § 250.198), and outlining areas in which potential ignition sources, other than electrical, are to be installed. The area outlined will include the following information:
(A) All major production equipment, wells, and other significant hydrocarbon sources and a description of the type of decking, ceiling, walls (e.g., grating or solid) and firewalls; and
(B) Location of generators, control rooms, panel boards, major cabling/conduit routes, and identification of the primary wiring method (e.g., type cable, conduit, or wire).
(ii) Elementary electrical schematic of any platform safety shut-down system with a functional legend.
(5) Certification that the design for the mechanical and electrical systems to be installed were approved by registered professional engineers. After these systems are installed, the lessee shall submit a statement to the District Manager certifying that new installations conform to the approved designs of this subpart.
(6) The design and schematics of the installation and maintenance of all fire- and gas-detection systems shall include the following:
(i) Type, location, and number of detection sensors;
(ii) Type and kind of alarms, including emergency equipment to be activated;
(iii) Method used for detection;
(iv) Method and frequency of calibration; and
(v) A functional block diagram of the detection system, including the electric power supply.
(7) The service fee listed in § 250.125. The fee you must pay will be determined by the number of components involved in the review and approval process.
[53 FR 10690, Apr. 1, 1988, as amended at 61 FR 60024, Nov. 26, 1996. Redesignated and amended at 63 FR 29479, 29485, May 29, 1998; 65 FR 219, Jan. 4, 2000; 67 FR 51759, Aug. 9, 2002; 71 FR 40912, July 19, 2006; 72 FR 12096, Mar. 15, 2007; 72 FR 25201, May 4, 2007]
§ 250.803
Additional production system requirements.
(a) For all production platforms, you must comply with the following production safety system requirements, in addition to the requirements of § 250.802 of this subpart and the requirements of API RP 14C (incorporated by reference as specified in 30 CFR 250.198).
(b) Design, installation, and operation of additional production systems—(1) Pressure and fired vessels. Pressure and fired vessels must be designed, fabricated, and code stamped in accordance with the applicable provisions of Sections I, IV, and VIII of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code. Pressure and fired vessels must have maintenance inspection, rating, repair, and alteration performed in accordance with the applicable provisions of API Pressure Vessel Inspection Code: In-Service Inspection, Rating, Repair, and Alteration, API 510 (except Sections 6.5 and 8.5) (incorporated by reference as specified in § 250.198).
(i) Pressure relief valves shall be designed, installed, and maintained in accordance with applicable provisions of sections I, IV, and VIII of the ASME Boiler and Pressure Vessel Code. The relief valves shall conform to the valve-sizing and pressure-relieving requirements specified in these documents; however, the relief valves, except completely redundant relief valves, shall be set no higher than the maximum-allowable working pressure of the vessel. All relief valves and vents shall be piped in such a way as to prevent fluid from striking personnel or ignition sources.
(ii) Steam generators operating at less than 15 pounds per square inch gauge (psig) shall be equipped with a level safety low (LSL) sensor which will shut off the fuel supply when the water level drops below the minimum safe level. Steam generators operating at greater than 15 psig require, in addition to an LSL, a water-feeding device which will automatically control the water level.
(iii) The lessee shall use pressure recorders to establish the new operating pressure ranges of pressure vessels at any time when there is a change in operating pressures that requires new settings for the high-pressure shut-in sensor and/or the low-pressure shut-in sensor as provided herein. The pressure-recorder charts used to determine current operating pressure ranges shall be maintained at the lessee's field office nearest the OCS facility or at other locations conveniently available to the District Manager. The high-pressure shut-in sensor shall be set no higher than 15 percent or 5 psi, whichever is greater, above the highest operating pressure of the vessel. This setting shall also be set sufficiently below (5 percent or 5 psi, whichever is greater) the relief valve's set pressure to assure that the pressure source is shut in before the relief valve activates. The low-pressure shut-in sensor shall activate no lower than 15 percent or 5 psi, whichever is greater, below the lowest pressure in the operating range. The activation of low-pressure sensors on pressure vessels which operate at less than 5 psi shall be approved by the District Manager on a case-by-case basis.
(2) Flowlines. (i) You must equip flowlines from wells with high- and low-pressure shut-in sensors located in accordance with section A.1 and Figure A1 of API RP 14C (incorporated by reference as specified in § 250.198). The lessee shall use pressure recorders to establish the new operating pressure ranges of flowlines at any time when there is a significant change in operating pressures. The most recent pressure-recorder charts used to determine operating pressure ranges shall be maintained at the lessee's field office nearest the OCS facility or at other locations conveniently available to the District Manager. The high-pressure shut-in sensor(s) shall be set no higher than 15 percent or 5 psi, whichever is greater, above the highest operating pressure of the line. But in all cases, it shall be set sufficiently below the maximum shut-in wellhead pressure or the gas-lift supply pressure to assure actuation of the SSV. The low-pressure shut-in sensor(s) shall be set no lower than 15 percent or 5 psi, whichever is greater, below the lowest operating pressure of the line in which it is installed.
(ii) If a well flows directly to the pipeline before separation, the flowline and valves from the well located upstream of and including the header inlet valve(s) shall have a working pressure equal to or greater than the maximum shut-in pressure of the well unless the flowline is protected by one of the following:
(A) A relief valve which vents into the platform flare scrubber or some other location approved by the District Manager. The platform flare scrubber shall be designed to handle, without liquid-hydrocarbon carryover to the flare, the maximum-anticipated flow of liquid hydrocarbons which may be relieved to the vessel.
(B) Two SSV's with independent high-pressure sensors installed with adequate volume upstream of any block valve to allow sufficient time for the valve(s) to close before exceeding the maximum allowable working pressure.
(iii) If you are installing flowlines constructed of unbonded flexible pipe on a floating platform, you must:
(A) Review the manufacturer's Design Methodology Verification Report and the independent verification agent's (IVA's) certificate for the design methodology contained in that report to ensure that the manufacturer has complied with the requirements of API Spec 17J (incorporated by reference as specified in 30 CFR 250.198);
(B) Determine that the unbonded flexible pipe is suitable for its intended purpose on the lease or pipeline right-of-way;
(C) Submit to the MMS District Manager the manufacturer's design specifications for the unbonded flexible pipe; and
(D) Submit to the MMS District Manager a statement certifying that the pipe is suitable for its intended use and that the manufacturer has complied with the IVA requirements of API Spec 17J (incorporated by reference as specified in 30 CFR 250.198).
(3) Safety sensors. All shutdown devices, valves, and pressure sensors shall function in a manual reset mode. Sensors with integral automatic reset shall be equipped with an appropriate device to override the automatic reset mode. All pressure sensors shall be equipped to permit testing with an external pressure source.
(4) ESD. The ESD must conform to the requirements of Appendix C, section C1, of API RP 14C (incorporated by reference as specified in § 250.198), and the following:
(i) The manually operated ESD valve(s) shall be quick-opening and nonrestricted to enable the rapid actuation of the shutdown system. Only ESD stations at the boat landing may utilize a loop of breakable synthetic tubing in lieu of a valve.
(ii) Closure of the SSV shall not exceed 45 seconds after automatic detection of an abnormal condition or actuation of an ESD. The surface-controlled SSSV shall close in not more than 2 minutes after the shut-in signal has closed the SSV. Design-delayed closure time greater than 2 minutes shall be justified by the lessee based on the individual well's mechanical/production characteristics and be approved by the District Manager.
(iii) A schematic of the ESD which indicates the control functions of all safety devices for the platforms shall be maintained by the lessee on the platform or at the lessee's field office nearest the OCS facility or other location conveniently available to the District Manager.
(5) Engines—(i) Engine exhaust. You must equip engine exhausts to comply with the insulation and personnel protection requirements of API RP 14C, section 4.2c(4) (incorporated by reference as specified in § 250.198). Exhaust piping from diesel engines must be equipped with spark arresters.
(ii) Diesel engine air intake. No later than May 31, 1989, diesel engine air intakes shall be equipped with a device to shutdown the diesel engine in the event of runaway. Diesel engines which are continuously attended shall be equipped with either remote operated manual or automatic shutdown devices. Diesel engines which are not continuously attended shall be equipped with automatic shutdown devices.
(6) Glycol dehydration units. A pressure relief system or an adequate vent shall be installed on the glycol regenerator (reboiler) which will prevent overpressurization. The discharge of the relief valve shall be vented in a nonhazardous manner.
(7) Gas compressors. You must equip compressor installations with the following protective equipment as required in API RP 14C, Sections A4 and A8 (incorporated by reference as specified in § 250.198).
(i) A Pressure Safety High (PSH), a Pressure Safety Low (PSL), a Pressure Safety Valve (PSV), and a Level Safety High (LSH), and an LSL to protect each interstage and suction scrubber.
(ii) A Temperature Safety High (TSH) on each compressor discharge cylinder.
(iii) The PSH and PSL shut-in sensors and LSH shut-in controls protecting compressor suction and interstage scrubbers shall be designated to actuate automatic shutdown valves (SDV) located in each compressor suction and fuel gas line so that the compressor unit and the associated vessels can be isolated from all input sources. All automatic SDV's installed in compressor suction and fuel gas piping shall also be actuated by the shutdown of the prime mover. Unless otherwise approved by the District Manager, gas—well gas affected by the closure of the automatic SDV on a compressor suction shall be diverted to the pipeline or shut in at the wellhead.
(iv) A blowdown valve is required on the discharge line of all compressor installations of 1,000 horsepower (746 kilowatts) or greater.
(8) Firefighting systems. Firefighting systems for both open and totally enclosed platforms installed for extreme weather conditions or other reasons shall conform to subsection 5.2, Firewater systems, of API RP 14G (incorporated by reference as specified in § 250.198), Fire Prevention and Control Open Type Offshore Production Platforms, and shall require approval of the District Manager. The following additional requirements shall apply for both open- and closed-production platforms:
(i) A firewater system consisting of rigid pipe with firehose stations or fixed firewater monitors shall be installed. The firewater system shall be installed to provide needed protection in all areas where production-handling equipment is located. A fixed waterspray system shall be installed in enclosed well-bay areas where hydrocarbon vapors may accumulate.
(ii) Fuel or power for firewater pump drivers shall be available for at least 30 minutes of run time during a platform shut-in. If necessary, an alternate fuel or power supply shall be installed to provide for this pump-operating time unless an alternate firefighting system has been approved by the District Manager.
(iii) A firefighting system using chemicals may be used in lieu of a water system if the District Manager determines that the use of a chemical system provides equivalent fire-protection control.
(iv) A diagram of the firefighting system showing the location of all firefighting equipment shall be posted in a prominent place on the facility or structure.
(v) For operations in subfreezing climates, the lessee shall furnish evidence to the District Manager that the firefighting system is suitable for the conditions.
(9) Fire- and gas-detection system. (i) Fire (flame, heat, or smoke) sensors shall be installed in all enclosed classified areas. Gas sensors shall be installed in all inadequately ventilated, enclosed classified areas. Adequate ventilation is defined as ventilation which is sufficient to prevent accumulation of significant quantities of vapor-air mixture in concentrations over 25 percent of the lower explosive limit (LEL). One approved method of providing adequate ventilation is a change of air volume each 5 minutes or 1 cubic foot of air-volume flow per minute per square foot of solid floor area, whichever is greater. Enclosed areas (e.g., buildings, living quarters, or doghouses) are defined as those areas confined on more than four of their six possible sides by walls, floors, or ceilings more restrictive to air flow than grating or fixed open louvers and of sufficient size to all entry of personnel. A classified area is any area classified Class I, Group D, Division 1 or 2, following the guidelines of API RP 500 (incorporated by reference as specified in § 250.198), or any area classified Class I, Zone 0, Zone 1, or Zone 2, following the guidelines of API RP 505 (incorporated by reference as specified in § 250.198).
(ii) All detection systems shall be capable of continuous monitoring. Fire-detection systems and portions of combustible gas-detection systems related to the higher gas concentration levels shall be of the manual-reset type. Combustible gas-detection systems related to the lower gas-concentration level may be of the automatic-reset type.
(iii) A fuel-gas odorant or an automatic gas-detection and alarm system is required in enclosed, continuously manned areas of the facility which are provided with fuel gas. Living quarters and doghouses not containing a gas source and not located in a classified area do not require a gas detection system.
(iv) The District Manager may require the installation and maintenance of a gas detector or alarm in any potentially hazardous area.
(v) Fire- and gas-detection systems must be an approved type, designed and installed according to API RP 14C, API RP 14G, and either API RP 14F or API RP 14FZ (the preceding four documents incorporated by reference as specified in § 250.198).
(10) Electrical equipment. Electrical equipment and systems shall be designed, installed, and maintained in accordance with the requirements in § 250.114 of this part.
(11) Erosion. A program of erosion control shall be in effect for wells or fields having a history of sand production. The erosion-control program may include sand probes, X-ray, ultrasonic, or other satisfactory monitoring methods. Records by lease, indicating the wells which have erosion-control programs in effect and the results of the programs, shall be maintained by the lessee for a period of 2 years and shall be made available to MMS upon request.
(c) General platform operations. (1) Surface or subsurface safety devices shall not be bypassed or blocked out of service unless they are temporarily out of service for startup, maintenance, or testing procedures. Only the minimum number of safety devices shall be taken out of service. Personnel shall monitor the bypassed or blocked-out functions until the safety devices are placed back in service. Any surface or subsurface safety device which is temporarily out of service shall be flagged.
(2) When wells are disconnected from producing facilities and blind flanged, equipped with a tubing plug, or the master valves have been locked closed, you are not required to comply with the provisions of API RP 14C (incorporated by reference as specified in § 250.198) or this regulation concerning the following:
(i) Automatic fail-close SSV's on wellhead assemblies, and
(ii) The PSH and PSL shut-in sensors in flowlines from wells.
(3) When pressure or atmospheric vessels are isolated from production facilities (e.g., inlet valve locked closed or inlet blind-flanged) and are to remain isolated for an extended period of time, safety device compliance with API RP 14C or this subpart is not required.
(4) All open-ended lines connected to producing facilities and wells shall be plugged or blind-flanged, except those lines designed to be open-ended such as flare or vent lines.
(d) Welding and burning practices and procedures. All welding, burning, and hot-tapping activities shall be conducted according to the specific requirements in §§ 250.109 through 250.113 of this part.
[53 FR 10690, Apr. 1, 1988; 53 FR 12227, Apr. 13, 1988, as amended at 55 FR 47753, Nov. 15, 1990; 61 FR 60025, Nov. 26, 1996. Redesignated and amended at 63 FR 29479, 29485, May 29, 1998; 65 FR 219, Jan. 4, 2000; 67 FR 51759, Aug. 9, 2002; 68 FR 43298, July 22, 2003; 68 FR 65172, Nov. 19, 2003; 70 FR 7403, Feb. 14, 2005; 70 FR 41575, July 19, 2005; 72 FR 12096, Mar. 15, 2007; 73 FR 20171, Apr. 15, 2008]
§ 250.804
Production safety-system testing and records.
(a) Inspection and testing. The safety-system devices shall be successfully inspected and tested by the lessee at the interval specified below or more frequently if operating conditions warrant. Testing must be in accordance with API RP 14C, Appendix D (incorporated by reference as specified in § 250.198), and the following:
(1) Testing requirements for subsurface safety devices are as follows:
(i) Each surface-controlled subsurface safety device installed in a well, including such devices in shut-in and injection wells, shall be tested in place for proper operation when installed or reinstalled and thereafter at intervals not exceeding 6 months. If the device does not operate properly, or if a liquid leakage rate in excess of 200 cubic centimeters per minute or a gas leakage rate in excess of 5 cubic feet per minute is observed, the device shall be removed, repaired and reinstalled, or replaced. Testing shall be in accordance with API RP 14B to ensure proper operation.
(ii) Each subsurface-controlled SSSV installed in a well shall be removed, inspected, and repaired or adjusted, as necessary, and reinstalled or replaced at intervals not exceeding 6 months for those valves not installed in a landing nipple and 12 months for those valves installed in a landing nipple.
(iii) Each tubing plug installed in a well shall be inspected for leakage by opening the well to possible flow at intervals not exceeding 6 months. If a liquid leakage rate in excess of 200 cubic centimeters per minute or a gas leakage rate in excess of 5 cubic feet per minute is observed, the device shall be removed, repaired and reinstalled, or replaced. An additional tubing plug may be installed in lieu of removal.
(iv) Injection valves shall be tested in the manner as outlined for testing tubing plugs in paragraph (a)(1)(iii) of this section. Leakage rates outlined in paragraph (a)(1)(iii) of this section shall apply.
(2) All PSV's shall be tested for operation at least once every 12 months. These valves shall be either bench-tested or equipped to permit testing with an external pressure source. Weighted disk vent valves used as PSV's on atmospheric tanks may be disassembled and inspected in lieu of function testing.
(3) The following safety devices (excluding electronic pressure transmitters and level sensors) must be tested at least once each calendar month, but at no time will more than 6 weeks elapse between tests:
(i) All PSH and PSL,
(ii) All LSH and LSL controls,
(iii) All automatic inlet SDV's which are actuated by a sensor on a vessel or compressor, and
(iv) All SDV's in liquid discharge lines and actuated by vessel low-level sensors.
(4) The following electronic pressure transmitters and level sensors must be tested at least once every 3 months, but at no time may more than 120 days elapse between tests:
(i) All PSH and PSL, and
(ii) All LSH and LSL controls.
(5) All SSV's and USV's shall be tested for operation and for leakage at least once each calendar month, but at no time shall more than 6 weeks elapse between tests. The SSV's and USV's must be tested in accordance with the test procedures specified in API RP 14H (incorporated by reference as specified in § 250.198). If the SSV or USV does not operate properly or if any fluid flow is observed during the leakage test, the valve shall be repaired or replaced.
(6) All flowline Flow Safety Valves (FSV) shall be checked for leakage at least once each calendar month, but at no time shall more than 6 weeks elapse between tests. The FSV's must be tested for leakage in accordance with the test procedures specified in API RP 14C, Appendix D, section D4, table D2, subsection D (incorporated by reference as specified in § 250.198). If the leakage measured exceeds a liquid flow of 200 cubic centimeters per minute or a gas flow of 5 cubic feet per minute, the FSV's shall be repaired or replaced.
(7) The TSH shutdown controls installed on compressor installations which can be nondestructively tested shall be tested every 6 months and repaired or replaced as necessary.
(8) All pumps for firewater systems shall be inspected and operated weekly.
(9) All fire- (flame, heat, or smoke) detection systems shall be tested for operation and recalibrated every 3 months provided that testing can be performed in a nondestructive manner. Open flame or devices operating at temperatures which could ignite a methane-air mixture shall not be used. All combustible gas-detection systems shall be calibrated every 3 months.
(10) All TSH devices shall be tested at least once every 12 months, excluding those addressed in paragraph (a)(7) of this section and those which would be destroyed by testing. Burner safety low and flow safety low devices shall also be tested at least once every 12 months.
(11) The ESD shall be tested for operation at least once each calendar month, but at no time shall more than 6 weeks elapse between tests. The test shall be conducted by alternating ESD stations monthly to close at least one wellhead SSV and verify a surface-controlled SSSV closure for that well as indicated by control circuitry actuation.
(12) Prior to the commencement of production, the lessee shall notify the District Manager when the lessee is ready to conduct a preproduction test and inspection of the integrated safety system. The lessee shall also notify the District Manager upon commencement of production in order that a complete inspection may be conducted.
(b) Records. The lessee shall maintain records for a period of 2 years for each subsurface and surface safety device installed. These records shall be maintained by the lessee at the lessee's field office nearest the OCS facility or other locations conveniently available to the District Manager. These records shall be available for review by a representative of MMS. The records shall show the present status and history of each device, including dates and details of installation, removal, inspection, testing, repairing, adjustments, and reinstallation.
[53 FR 10690, Apr. 1, 1988, as amended at 55 FR 47753, Nov. 15, 1990; 62 FR 5331, Feb. 5, 1997. Redesignated at 63 FR 29479, May 29, 1998, as amended at 65 FR 35824, June 6, 2000; 67 FR 51760, Aug. 9, 2002; 68 FR 47, Jan. 2, 2003]
§ 250.805
Safety device training.
Personnel installing, inspecting, testing, and maintaining these safety devices and personnel operating the production platforms shall be qualified in accordance with subpart O.
§ 250.806
Safety and pollution prevention equipment quality assurance requirements.
(a) General requirements. (1) Except as provided in paragraph (b)(1) of this section, you may install only certified safety and pollution prevention equipment (SPPE) in wells located on the OCS. SPPE includes the following:
(i) Surface safety valves (SSV) and actuators;
(ii) Underwater safety valves (USV) and actuators; and
(iii) Subsurface safety valves (SSSV) and associated safety valve locks and landing nipples.
(2) Certified SPPE is equipment the manufacturer certifies as manufactured under a quality assurance program MMS recognizes. MMS considers all other SPPE as noncertified. MMS recognizes two quality assurance programs:
(i) ANSI/ASME SPPE-1, Quality Assurance and Certification of Safety and Pollution-Prevention Equipment Used in Offshore Oil and Gas Operations; and
(ii) API Spec Q1, Specification for Quality Programs for the Petroleum, Petrochemical and Natural Gas Industry (incorporated by reference as specified in § 250.198).
(3) All SSV's and USV's must meet the technical specifications of API Spec 6A and 6AV1. All SSSVs must meet the technical specifications of API Specification 14A.
(4) For information on all standards mentioned in this section, see § 250.198.
(b) Use of noncertified SPPE. (1) Before April 1, 1998, you may continue to use and install noncertified SPPE if it was in your inventory as of April 1, 1988, and was included in a list of noncertified SPPE submitted to MMS prior to August 29, 1988.
(2) On or after April 1, 1998:
(i) You may not install additional noncertified SPPE; and
(ii) When noncertified SPPE that is already in service requires offsite repair, remanufacturing, or hot work such as welding, you must replace it with certified SPPE.
(c) Recognizing other quality assurance programs. The MMS will consider recognizing other quality assurance programs covering the manufacture of SPPE. If you want MMS to evaluate other quality assurance programs, submit relevant information about the program and reasons for recognition by MMS to the Chief, Office of Offshore Regulatory Programs; Minerals Management Service; MS-4020; 381 Elden Street, Herndon, Virginia 20170-4817.
[62 FR 42671, Aug. 8, 1997. Redesignated at 63 FR 29479, May 29, 1998, as amended at 63 FR 37068, July 9, 1998; 65 FR 76935, Dec. 8, 2000; 72 FR 12096, Mar. 15, 2007; 73 FR 20171, Apr. 15, 2008]
§ 250.807
Hydrogen sulfide.
Production operations in zones known to contain hydrogen sulfide (H2S) or in zones where the presence of H2S is unknown, as defined in § 250.490 of this part, shall be conducted in accordance with that section and other relevant requirements of subpart H, Production Safety Systems.
[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 29485, May 29, 1998; 68 FR 8435, Feb. 20, 2003]

Subpart I—Platforms and Structures

Source:
70 FR 41575, July 19, 2005, unless otherwise noted.

General Requirements for Platforms
§ 250.900
What general requirements apply to all platforms?
(a) You must design, fabricate, install, use, maintain, inspect, and assess all platforms and related structures on the Outer Continental Shelf (OCS) so as to ensure their structural integrity for the safe conduct of drilling, workover, and production operations. In doing this, you must consider the specific environmental conditions at the platform location.
(b) You must also submit an application under § 250.905 of this subpart and obtain the approval of the Regional Supervisor before performing any of the activities described in the following table:
Activity requiring application and approval | Conditions for conducting the activity
(1) Install a platform. This includes placing a newly constructed platform at a location or moving an existing platform to a new site | (i) You must adhere to the requirements of this subpart, including the industry standards in § 250.901. (ii) If you are installing a floating platform, you must also adhere to U.S. Coast Guard (USCG) regulations for the fabrication, installation, and inspection of floating OCS facilities.
(2) Major modification to any platform. This includes any structural changes that materially alter the approved plan or cause a major deviation from approved operations and any modification that increases loading on a platform by 10 percent or more | (i) You must adhere to the requirements of this subpart, including the industry standards in § 250.901. (ii) Before you make a major modification to a floating platform, you must obtain approval from both the MMS and the USCG for the modification.
(3) Major repair of damage to any platform. This includes any corrective operations involving structural members affecting the structural integrity of a portion or all of the platform | (i) You must adhere to the requirements of this subpart, including the industry standards in § 250.901. (ii) Before you make a major repair to a floating platform, you must obtain approval from both the MMS and the USCG for the repair.
(4) Convert an existing platform at the current location for a new purpose | (i) The Regional Supervisor will determine on a case-by-case basis the requirements for an application for conversion of an existing platform at the current location. (ii) At a minimum, your application must include: the converted platform's intended use; and a demonstration of the adequacy of the design and structural condition of the converted platform. (iii) If a floating platform, you must also adhere to USCG regulations for the fabrication, installation, and inspection of floating OCS facilities.
(5) Convert an existing mobile offshore drilling unit (MODU) for a new purpose | (i) The Regional Supervisor will determine on a case-by-case basis the requirements for an application for conversion of an existing MODU. (ii) At a minimum, your application must include: the converted MODU's intended location and use; a demonstration of the adequacy of the design and structural condition of the converted MODU; and a demonstration that the level of safety for the converted MODU is at least equal to that of re-used platforms. (iii) You must also adhere to USCG regulations for the fabrication, installation, and inspection of floating OCS facilities.
(c) Under emergency conditions, you may make repairs to primary structural elements to restore an existing permitted condition without an application or prior approval. You must notify the Regional Supervisor of the damage that occurred within 24 hours, and you must notify the Regional Supervisor of the repairs that were made within 24 hours of completing the repairs. If you make emergency repairs on a floating platform, you must also notify the USCG.
(d) You must determine if your new platform or major modification to an existing platform is subject to the Platform Verification Program (PVP). Section 250.910 of this subpart fully describes the facilities that are subject to the PVP. If you determine that your platform is subject to the PVP, you must follow the requirements of §§ 250.909-250.918 of this subpart.
(e) MMS will cancel your approved platform installation permits one year after the approval is granted if the platform is not installed. If MMS cancels your permit approval, you must resubmit your application.
[70 FR 41575, July 19, 2005; 71 FR 16859, Apr. 4, 2006, as amended at 73 FR 20171, Apr. 15, 2008]
§ 250.901
What industry standards must your platform meet?
(a) In addition to the other requirements of this subpart, your plans for platform design, analysis, fabrication, installation, use, maintenance, inspection and assessment must, as appropriate, conform to:
(1) American Concrete Institute (ACI) Standard 318, Building Code Requirements for Reinforced Concrete, plus Commentary, (incorporated by reference as specified in § 250.198);
(2) ACI 357R, Guide for the Design and Construction of Fixed Offshore Concrete Structures, (incorporated by reference as specified in § 250.198);
(3) ANSI/AISC 360-05, Specification for Structural Steel Buildings, (incorporated by reference as specified in § 250.198);
(4) American Petroleum Institute (API) Bulletin 2INT-DG, Interim Guidance for Design of Offshore Structures for Hurricane Conditions, (incorporated by reference as specified in § 250.198);
(5) API Bulletin 2INT-EX, Interim Guidance for Assessment of Existing Offshore Structures for Hurricane Conditions, (incorporated by reference as specified in § 250.198);
(6) API Bulletin 2INT-MET, Interim Guidance on Hurricane Conditions in the Gulf of Mexico, (incorporated by reference as specified in § 250.198);
(7) API Recommend Practice (RP) 2A-WSD, RP for Planning, Designing, and Constructing Fixed Offshore Platforms—Working Stress Design (incorporated by reference as specified in § 250.198);
(8) API RP 2FPS, Recommended Practice for Planning, Designing, and Constructing Floating Production Systems, (incorporated by reference as specified in § 250.198);
(9) API RP 2RD, Design of Risers for Floating Production Systems (FPSs) and Tension-Leg Platforms (TLPs), (incorporated by reference as specified in § 250.198);
(10) API RP 2SK, Recommended Practice for Design and Analysis of Station Keeping Systems for Floating Structures, (incorporated by reference as specified in § 250.198);
(11) API RP 2SM, Recommended Practice for Design, Manufacture, Installation, and Maintenance of Synthetic Fiber Ropes for Offshore Mooring, (incorporated by reference as specified in § 250.198);
(12) API RP 2T, Recommended Practice for Planning, Designing and Constructing Tension Leg Platforms, (incorporated by reference as specified in § 250.198);
(13) API RP 14J, Recommended Practice for Design and Hazards Analysis for Offshore Production Facilities, (incorporated by reference as specified in § 250.198);
(14) American Society for Testing and Materials (ASTM) Standard C 33-99a, Standard Specification for Concrete Aggregates, (incorporated by reference as specified in § 250.198);
(15) ASTM Standard C 94/C 94M-99, Standard Specification for Ready-Mixed Concrete, (incorporated by reference as specified in § 250.198);
(16) ASTM Standard C 150-99, Standard Specification for Portland Cement, (incorporated by reference as specified in § 250.198);
(17) ASTM Standard C 330-99, Standard Specification for Lightweight Aggregates for Structural Concrete, (incorporated by reference as specified in § 250.198);
(18) ASTM Standard C 595-98, Standard Specification for Blended Hydraulic Cements, (incorporated by reference as specified in § 250.198);
(19) AWS D1.1, Structural Welding Code—Steel, including Commentary, (incorporated by reference as specified in § 250.198);
(20) AWS D1.4, Structural Welding Code—Reinforcing Steel, (incorporated by reference as specified in § 250.198);
(21) AWS D3.6M, Specification for Underwater Welding, (incorporated by reference as specified in § 250.198);
(22) NACE Standard MR0175, Sulfide Stress Cracking Resistant Metallic Materials for Oilfield Equipment, (incorporated by reference as specified in § 250.198);
(23) NACE Standard RP0176-2003, Item No. 21018, Standard Recommended Practice, Corrosion Control of Steel Fixed Offshore Structures Associated with Petroleum Production.
(b) You must follow the requirements contained in the documents listed under paragraph (a) of this section insofar as they do not conflict with other provisions of 30 CFR Part 250. You may use applicable provisions of these documents, as approved by the Regional Supervisor, for the design, fabrication, and installation of platforms such as spars, since standards specifically written for such structures do not exist. You may also use alternative codes, rules, or standards, as approved by the Regional Supervisor, under the conditions enumerated in § 250.141.
(c) For information on the standards mentioned in this section, and where they may be obtained, see § 250.198 of this part.
(d) The following chart summarizes the applicability of the industry standards listed in this section for fixed and floating platforms:
Industry standard | Applicable to * * *
(1) ACI Standard 318, Building Code Requirements for Reinforced Concrete, Plus Commentary; | Fixed and floating platform, as appropriate.
(2) ANSI/AISC 360-05, Specification for Structural Steel Buildings;
(3) API Bulletin 2INT-DG, Interim Guidance for Design of Offshore Structures for Hurricane Conditions;
(4) API Bulletin 2INT-EX, Interim Guidance for Assessment of Existing Offshore Structures for Hurricane Conditions;
(5) API Bulletin 2INT-MET, Interim Guidance on Hurricane Conditions in the Gulf of Mexico;
(6) API RP 2A-WSD, RP for Planning, Designing, and Constructing Fixed Offshore Platforms—Working Stress Design;
(7) ASTM Standard C33-99a, Standard Specification for Concrete Aggregates;
(8) ASTM Standard C94/C94M-99, Standard Specification for Ready-Mixed Concrete;
(9) ASTM Standard C150-99, Standard Specification for Portland Cement;
(10) ASTM Standard C330-99, Standard Specification for Lightweight Aggregates for Structural Concrete;
(11) ASTM Standard C 595-98, Standard Specification for Blended Hydraulic Cements;
(12) AWS D1.1, Structural Welding Code—Steel;
(13) AWS D1.4, Structural Welding Code—Reinforcing Steel;
(14) AWS D3.6M, Specification for Underwater Welding;
(15) NACE Standard RP 0176-2003, Standard Recommended Practice (RP), Corrosion Control of Steel Fixed Offshore Platforms Associated with Petroleum Production;
(16) ACI 357R, Guide for the Design and Construction of Fixed Offshore Concrete Structures; | Fixed platforms.
(17) API RP 14J, RP for Design and Hazards Analysis for Offshore Production Facilities; | Floating platforms.
(18) API RP 2FPS, RP for Planning, Designing, and Constructing, Floating Production Systems;
(19) API RP 2RD, Design of Risers for Floating Production Systems (FPSs) and Tension-Leg Platforms (TLPs);
(20) API RP 2SK, RP for Design and Analysis of Station Keeping Systems for Floating Structures;
(21) API RP 2T, RP for Planning, Designing, and Constructing Tension Leg Platforms;
(22) API RP 2SM, RP for Design, Manufacture, Installation, and Maintenance of Synthetic Fiber Ropes for Offshore Mooring.
[70 FR 41575, July 19, 2005, as amended at 72 FR 12096, Mar. 15, 2007; 73 FR 20169, Apr. 15, 2008]
§ 250.902
What are the requirements for platform removal and location clearance?
You must remove all structures according to §§ 250.1725 through 250.1730 of Subpart Q—Decommissioning Activities of this part.
§ 250.903
What records must I keep?
(a) You must compile, retain, and make available to MMS representatives for the functional life of all platforms:
(1) The as-built drawings;
(2) The design assumptions and analyses;
(3) A summary of the fabrication and installation nondestructive examination records;
(4) The inspection results from the inspections required by § 250.919 of this subpart; and
(5) Records of repairs not covered in the inspection report submitted under § 250.919(b).
(b) You must record and retain the original material test results of all primary structural materials during all stages of construction. Primary material is material that, should it fail, would lead to a significant reduction in platform safety, structural reliability, or operating capabilities. Items such as steel brackets, deck stiffeners and secondary braces or beams would not generally be considered primary structural members (or materials).
(c) You must provide MMS with the location of these records in the certification statement of your application for platform approval as required in § 250.905(j).

Platform Approval Program
§ 250.904
What is the Platform Approval Program?
(a) The Platform Approval Program is the MMS basic approval process for platforms on the OCS. The requirements of the Platform Approval Program are described in §§ 250.904 through 250.908 of this subpart. Completing these requirements will satisfy MMS criteria for approval of fixed platforms of a proven design that will be placed in the shallow water areas (≤ 400 ft.) of the Gulf of Mexico OCS.
(b) The requirements of the Platform Approval Program must be met by all platforms on the OCS. Additionally, if you want approval for a floating platform; a platform of unique design; or a platform being installed in deepwater (> 400 ft.) or a frontier area, you must also meet the requirements of the Platform Verification Program. The requirements of the Platform Verification Program are described in §§ 250.909 through 250.918 of this subpart.
§ 250.905
How do I get approval for the installation, modification, or repair of my platform?
The Platform Approval Program requires that you submit the information, documents, and fee listed in the following table for your proposed project.
Required submittal | Required contents | Other requirements
(a) Application cover letter | Proposed structure designation, lease number, area, name, and block number, and the type of facility your facility (e.g., drilling, production, quarters). The structure designation must be unique for the field (some fields are made up of several blocks); i.e. once a platform “A” has been used in the field there should never be another platform “A” even if the old platform “A” has been removed. Single well free standing caissons should be given the same designation as the well. All other structures are to be designated by letter designations | You must submit three copies. If, your facility is subject to the Platform Verficiation Program (PVP), you must submit four copies.
(b) Location plat | Latitude and longitude coordinates, Universal Mercator grid-system coordinates, state plane coordinates in the Lambert or Transverse Mercator Projection System, and distances in feet from the nearest block lines. These coordinates must be based on the NAD (North American Datum) 27 datum plane coordinate system | Your plat must be drawn to a scale of 1 inch equals 2,000 feet and include the coordinates of the lease block boundary lines. You must submit three
(c) Front, Side, and Plan View drawings | Platform dimensions and orientation, elevations relative to M.L.L.W. (Mean Lower Low Water), and pile sizes and penetration | Your drawing sizes must not exceed 11″ × 17″. You must submit three copies (four copies for PVP applications).
| (d) Complete set of structural drawings | The approved for construction fabrication drawings should be submitted including; e.g., cathodic protection systems; jacket design; pile foundations; drilling, production, and pipeline risers and riser tensioning systems; turrets and turret-and-hull interfaces; mooring and tethering systems; foundations and anchoring systems | Your drawing sizes must not exceed 11″ × 17″. You must submit one copy.
(e) Summary of environmental data | A summary of the environmental data described in the applicable standards referenced under § 250.901(a) of this subpart and in § 250.198 of Subpart A, where the data is used in the design or analysis of the platform. Examples of relevant data include information on waves, wind, current, tides, temperature, snow and ice effects, marine growth, and water depth | You must submit one copy.
(f) Summary of the engineering design data | Loading information (e.g., live, dead, environmental), structural information (e.g., design-life; material types; cathodic protection systems; design criteria; fatigue life; jacket design; deck design; production component design; pile foundations; drilling, production, and pipeline risers and riser tensioning systems; turrets and turret-and-hull interfaces; foundations, foundation pilings and templates, and anchoring systems; mooring or tethering systems; fabrication and installation guidelines), and foundation information (e.g., soil stability, design criteria) | You must submit one copy.
(g) Project-specific studies used in the platform design or installation | All studies pertinent to platform design or installation, e.g., oceanographic and/or soil reports including the overall site investigative report required in section 250.906 | You must submit one copy of each study.
(h) Description of the loads imposed on the facility | Loads imposed by jacket; decks; production components; drilling, production, and pipeline risers, and riser tensioning systems; turrets and turret-and-hull interfaces; foundations, foundation pilings and templates, and anchoring systems; and mooring or tethering systems | You must submit one copy.
(i) A copy of the in-service inspection plan | This plan is described in § 250.919. | You must submit one copy.
(j) Certification statement | The following statement: “The design of this structure has been certified by a recognized classification society, or a registered civil or structural engineer or equivalent, or a naval architect or marine engineer or equivalent, specializing in the design of offshore structures. The certified design and as-built plans and specifications will be on file at (give location)” | An authorized company representative must sign the statement. You must submit one copy.
(k) Payment of the service fee listed in § 250.125 | |
[70 FR 41575, July 19, 2005, as amended at 71 FR 40912, July 19, 2006]
§ 250.906
What must I do to obtain approval for the proposed site of my platform?
(a) Shallow hazards surveys. You must perform a high-resolution or acoustic-profiling survey to obtain information on the conditions existing at and near the surface of the seafloor. You must collect information through this survey sufficient to determine the presence of the following features and their likely effects on your proposed platform:
(1) Shallow faults;
(2) Gas seeps or shallow gas;
(3) Slump blocks or slump sediments;
(4) Shallow water flows;
(5) Hydrates; or
(6) Ice scour of seafloor sediments.
(b) Geologic surveys. You must perform a geological survey relevant to the design and siting of your platform. Your geological survey must assess:
(1) Seismic activity at your proposed site;
(2) Fault zones, the extent and geometry of faulting, and attenuation effects of geologic conditions near your site; and
(3) For platforms located in producing areas, the possibility and effects of seafloor subsidence.
(c) Subsurface surveys. Depending upon the design and location of your proposed platform and the results of the shallow hazard and geologic surveys, the Regional Supervisor may require you to perform a subsurface survey. This survey will include a testing program for investigating the stratigraphic and engineering properties of the soil that may affect the foundations or anchoring systems for your facility. The testing program must include adequate in situ testing, boring, and sampling to examine all important soil and rock strata to determine its strength classification, deformation properties, and dynamic characteristics. If required to perform a subsurface survey, you must prepare and submit to the Regional Supervisor a summary report to briefly describe the results of your soil testing program, the various field and laboratory test methods employed, and the applicability of these methods as they pertain to the quality of the samples, the type of soil, and the anticipated design application. You must explain how the engineering properties of each soil stratum affect the design of your platform. In your explanation you must describe the uncertainties inherent in your overall testing program, and the reliability and applicability of each test method.
(d) Overall site investigation report. You must prepare and submit to the Regional Supervisor an overall site investigation report for your platform that integrates the findings of your shallow hazards surveys and geologic surveys, and, if required, your subsurface surveys. Your overall site investigation report must include analyses of the potential for:
(1) Scouring of the seafloor;
(2) Hydraulic instability;
(3) The occurrence of sand waves;
(4) Instability of slopes at the platform location;
(5) Liquifaction, or possible reduction of soil strength due to increased pore pressures;
(6) Degradation of subsea permafrost layers;
(7) Cyclic loading;
(8) Lateral loading;
(9) Dynamic loading;
(10) Settlements and displacements;
(11) Plastic deformation and formation collapse mechanisms; and
(12) Soil reactions on the platform foundations or anchoring systems.
§ 250.907
Where must I locate foundation boreholes?
(a) For fixed or bottom-founded platforms and tension leg platforms, your maximum distance from any foundation pile to a soil boring must not exceed 500 feet.
(b) For deepwater floating platforms which utilize catenary or taut-leg moorings, you must take borings at the most heavily loaded anchor location, at the anchor points approximately 120 and 240 degrees around the anchor pattern from that boring, and, as necessary, other points throughout the anchor pattern to establish the soil profile suitable for foundation design purposes.
§ 250.908
What are the minimum structural fatigue design requirements?
(a) API RP 2A-WSD, Recommended Practice for Planning, Designing and Constructing Fixed Offshore Platforms (incorporated by reference as specified in 30 CFR 250.198), requires that the design fatigue life of each joint and member be twice the intended service life of the structure. When designing your platform, the following table provides minimum fatigue life safety factors for critical structural members and joints.
If . . . | Then . . .
(1) There is sufficient structural redundancy to prevent catastrophic failure of the platform or structure under consideration | The results of the analysis must indicate a maximum calculated life of twice the design life of the platform.
(2) There is not sufficient structural redundancy to prevent catastrophic failure of the platform or structure | The results of a fatigue analysis must indicate a minimum calculated life or three times the design life of the platform.
(3) The desirable degree of redundancy is significantly reduced as a result of fatigue damage | The results of a fatigue analysis must indicate a minimum calculated life of three times the design life of the platform.
(b) The documents incorporated by reference in § 250.901 may require larger safety factors than indicated in paragraph (a) of this section for some key components. When the documents incorporated by reference require a larger safety factor than the chart in paragraph (a) of this section, the requirements of the incorporated document will prevail.

Platform Verification Program
§ 250.909
What is the Platform Verification Program?
The Platform Verification Program is the MMS approval process for ensuring that floating platforms; platforms of a new or unique design; platforms in seismic areas; or platforms located in deepwater or frontier areas meet stringent requirements for design and construction. The program is applied during construction of new platforms and major modifications of, or repairs to, existing platforms. These requirements are in addition to the requirements of the Platform Approval Program described in §§ 250.904 through 250.908 of this subpart.
§ 250.910
Which of my facilities are subject to the Platform Verification Program?
(a) All new fixed or bottom-founded platforms that meet any of the following five conditions are subject to the Platform Verification Program:
(1) Platforms installed in water depths exceeding 400 feet (122 meters);
(2) Platforms having natural periods in excess of 3 seconds;
(3) Platforms installed in areas of unstable bottom conditions;
(4) Platforms having configurations and designs which have not previously been used or proven for use in the area; or
(5) Platforms installed in seismically active areas.
(b) All new floating platforms are subject to the Platform Verification Program to the extent indicated in the following table:
If . . . | Then . . .
(1) Your new floating platform is a buoyant offshore facility that does not have a ship-shaped hull | The entire platform is subject to the Platform Verification Program including the following associated structures:
| (i) Drilling, production, and pipeline risers, and riser tensioning systems (each platform must be designed to accommodate all the loads imposed by all risers and riser does not have tensioning systems); (ii) Turrets and turret-and-hull interfaces; (iii) Foundations, foundation pilings and templates, and anchoring systems; and (iv) Mooring or tethering systems.
(2) Your new floating platform is a buoyant offshore facility with a ship-shaped hull | Only the following structures that may be associated with a floating platform are subject to the Platform Verification Program:
| (i) Drilling, production, and pipeline risers, and riser tensioning systems (each platform must be designed to accommodate all the loads imposed by all risers and riser tensioning systems); (ii) Turrets and turret-and-hull interfaces; (iii) Foundations, foundation pilings and templates, and anchoring systems; and (iv) Mooring or tethering systems.
(c) If a platform is originally subject to the Platform Verification Program, then the conversion of that platform at that same site for a new purpose, or making a major modification of, or major repair to, that platform, is also subject to the Platform Verification Program. A major modification includes any modification that increases loading on a platform by 10 percent or more. A major repair is a corrective operation involving structural members affecting the structural integrity of a portion or all of the platform. Before you make a major modification or repair to a floating platform, you must obtain approval from both the MMS and the USCG.
(d) The applicability of Platform Verification Program requirements to other types of facilities will be determined by MMS on a case-by-case basis.
[70 FR 41575, July 19, 2005; 71 FR 28080, May 15, 2006]
§ 250.911
If my platform is subject to the Platform Verification Program, what must I do?
If your platform, conversion, or major modification or repair meets the criteria in § 250.910, you must:
(a) Design, fabricate, install, use, maintain and inspect your platform, conversion, or major modification or repair to your platform according to the requirements of this subpart, and the applicable documents listed in § 250.901(a) of this subpart;
(b) Comply with all the requirements of the Platform Approval Program found in §§ 250.904 through 250.908 of this subpart.
(c) Submit for the Regional Supervisor's approval three copies each of the design verification, fabrication verification, and installation verification plans required by § 250.912;
(d) Include your nomination of a Certified Verification Agent (CVA) as a part of each verification plan required by § 250.912;
(e) Follow the additional requirements in §§ 250.913 through 250.918;
(f) Obtain approval for modifications to approved plans and for major deviations from approved installation procedures from the Regional Supervisor; and
(g) Comply with applicable USCG regulations for floating OCS facilities.
§ 250.912
What plans must I submit under the Platform Verification Program?
If your platform, associated structure, or major modification meets the criteria in § 250.910, you must submit the following plans to the Regional Supervisor for approval:
(a) Design verification plan. You may submit your design verification plan with or subsequent to the submittal of your Development and Production Plan (DPP) or Development Operations Coordination Document (DOCD). Your design verification must be conducted by, or be under the direct supervision of, a registered professional civil or structural engineer or equivalent, or a naval architect or marine engineer or equivalent, with previous experience in directing the design of similar facilities, systems, structures, or equipment. For floating platforms, you must ensure that the requirements of the USCG for structural integrity and stability, e.g., verification of center of gravity, etc., have been met. Your design verification plan must include the following:
(1) All design documentation specified in § 250.905 of this subpart;
(2) Abstracts of the computer programs used in the design process; and
(3) A summary of the major design considerations and the approach to be used to verify the validity of these design considerations.
(b) Fabrication verification plan. The Regional Supervisor must approve your fabrication verification plan before you may initiate any related operations. Your fabrication verification plan must include the following:
(1) Fabrication drawings and material specifications for artificial island structures and major members of concrete-gravity and steel-gravity structures;
(2) For jacket and floating structures, all the primary load-bearing members included in the space-frame analysis; and
(3) A summary description of the following:
(i) Structural tolerances;
(ii) Welding procedures;
(iii) Material (concrete, gravel, or silt) placement methods;
(iv) Fabrication standards;
(v) Material quality-control procedures;
(vi) Methods and extent of nondestructive examinations for welds and materials; and
(vii) Quality assurance procedures.
(c) Installation verification plan. The Regional Supervisor must approve your installation verification plan before you may initiate any related operations. Your installation verification plan must include:
(1) A summary description of the planned marine operations;
(2) Contingencies considered;
(3) Alternative courses of action; and
(4) An identification of the areas to be inspected. You must specify the acceptance and rejection criteria to be used for any inspections conducted during installation, and for the post-installation verification inspection.
(d) You must combine fabrication verification and installation verification plans for manmade islands or platforms fabricated and installed in place.
§ 250.913
When must I resubmit Platform Verification Program plans?
(a) You must resubmit any design verification, fabrication verification, or installation verification plan to the Regional Supervisor for approval if:
(1) The CVA changes;
(2) The CVA's or assigned personnel's qualifications change; or
(3) The level of work to be performed changes.
(b) If only part of a verification plan is affected by one of the changes described in paragraph (a) of this section, you can resubmit only the affected part. You do not have to resubmit the summary of technical details unless you make changes in the technical details.
§ 250.914
How do I nominate a CVA?
(a) As part of your design verification, fabrication verification, or installation verification plan, you must nominate a CVA for the Regional Supervisor's approval. You must specify whether the nomination is for the design, fabrication, or installation phase of verification, or for any combination of these phases.
(b) For each CVA, you must submit a list of documents to be forwarded to the CVA, and a qualification statement that includes the following:
(1) Previous experience in third-party verification or experience in the design, fabrication, installation, or major modification of offshore oil and gas platforms. This should include fixed platforms, floating platforms, manmade islands, other similar marine structures, and related systems and equipment;
(2) Technical capabilities of the individual or the primary staff for the specific project;
(3) Size and type of organization or corporation;
(4) In-house availability of, or access to, appropriate technology. This should include computer programs, hardware, and testing materials and equipment;
(5) Ability to perform the CVA functions for the specific project considering current commitments;
(6) Previous experience with MMS requirements and procedures;
(7) The level of work to be performed by the CVA.
§ 250.915
What are the CVA's primary responsibilities?
(a) The CVA must conduct specified reviews according to §§ 250.916, 250.917, and 250.918 of this subpart.
(b) Individuals or organizations acting as CVAs must not function in any capacity that would create a conflict of interest, or the appearance of a conflict of interest.
(c) The CVA must consider the applicable provisions of the documents listed in § 250.901(a); the alternative codes, rules, and standards approved under 250.901(b); and the requirements of this subpart.
(d) The CVA is the primary contact with the Regional Supervisor and is directly responsible for providing immediate reports of all incidents that affect the design, fabrication and installation of the platform.
§ 250.916
What are the CVA's primary duties during the design phase?
(a) The CVA must use good engineering judgement and practices in conducting an independent assessment of the design of the platform, major modification, or repair. The CVA must ensure that the platform, major modification, or repair is designed to withstand the environmental and functional load conditions appropriate for the intended service life at the proposed location.
(b) Primary duties of the CVA during the design phase include the following:
Type of facility . . . | The CVA must . . .
(1) For fixed platforms and non-ship-shaped floating facilities | Conduct an independent assessment of all proposed:
| (i) Planning criteria;
| | (ii) Operational requirements;
| (iii) Environmental loading data;
| (iv) Load determinations;
| (v) Stress analyses;
| (vi) Material designations;
| (vii) Soil and foundation conditions;
| (viii) Safety factors; and
| (ix) Other pertinent parameters of the proposed design.
(2)For all floating facilities | Ensure that the requirements of the U.S. Coast Guard for structural integrity and stability, e.g., verification of center of gravity, etc., have been met. The CVA must also consider:
| (i) Drilling, production, and pipeline risers, and riser tensioning systems;
| (ii) Turrets and turret-and-hull interfaces;
| (iii) Foundations, foundation pilings and templates, and anchoring systems; and
| (iv) Mooring or tethering systems.
(c) The CVA must submit interim reports to the Regional Supervisor and to you, as appropriate. The CVA, upon completion of the design verification, must prepare a final report and submit one copy to the Regional Supervisor. The CVA must submit the final report within 90 days of the receipt of the design data, or within 90 days from the date the approval to act as a CVA was issued, whichever is later. The CVA must submit the final report to the Regional Supervisor before fabrication begins, and must include:
(1) A summary of the material reviewed and the CVA's findings;
(2) The CVA's recommendation that the Regional Supervisor either accept, request modifications, or reject the proposed design;
(3) The particulars of how, by whom, and when the independent review was conducted; and
(4) Any additional comments the CVA may deem necessary.
§ 250.917
What are the CVA's primary duties during the fabrication phase?
(a) The CVA must use good engineering judgement and practices in conducting an independent assessment of the fabrication activities. The CVA must monitor the fabrication of the platform or major modification to ensure that it has been built according to the approved design and the fabrication plan. If the CVA finds that fabrication procedures are changed or design specifications are modified, the CVA must inform you. If you accept the modifications, then the CVA must so inform the Regional Supervisor.
(b) Primary duties of the CVA during the fabrication phase include the following:
Type of facility . . . | The CVA must . . .
(1) For all fixed platforms and non-ship-shaped floating facilities | Make periodic onsite inspections while fabrication is in progress and must verify the following fabrication items, as appropriate:
| (i) Quality control by lessee and builder;
| (ii) Fabrication site facilities;
| (iii) Material quality and identification methods;
| (iv) Fabrication procedures specified in the approved plan, and adherence to such procedures;
| (v) Welder and welding procedure qualification and identification;
| (vi) Structural tolerences specified and adherence to those tolerances;
| (vii) The nondestructive examination requirements, and evaluation results of the specified examinations;
| (viii) Destructive testing requirements and results;
| (ix) Repair procedures;
| (x) Installation of corrosion-protection systems and splash-zone protection;
| (xi) Erection procedures to ensure that overstressing of structural members does not occur;
| (xii) Alignment procedures;
| | (xiii) Dimensional check of the overall structure, including any turrets, turret-and-hull interfaces, any mooring line and chain and riser tensioning line segments; and
| (xiv) Status of quality-control records at various stages of fabrication.
(2) For all floating facilities | Ensure that the requirements of the U.S. Coast Guard floating for structural integrity and stability, e.g., verification of center of gravity, etc., have been met. The CVA must also consider:
| (i) Drilling, production, and pipeline risers, and riser tensioning systems (at least for the initial fabrication of these elements);
| (ii) Turrets and turret-and-hull interfaces;
| (iii) Foundation pilings and templates, and anchoring systems; and
| (iv) Mooring or tethering systems.
(c) Reports. The CVA must submit interim reports to the Regional Supervisor and to you, as appropriate. The CVA must prepare a final report covering the adequacy of the entire fabrication phase. The final report need not cover aspects of the fabrication already included in interim reports. The CVA must submit one copy of the final report to the Regional Supervisor within 90 days after completion of the fabrication phase but before the beginning of the installation phase. In the final report the CVA must:
(1) Give details of how, by whom, and when the independent monitoring activities were conducted;
(2) Describe the CVA's activities during the verification process;
(3) Summarize the CVA's findings;
(4) Confirm or deny compliance with the design specifications and the approved fabrication plan;
(5) Make a recommendation to accept or reject the fabrication; and
(6) Provide any additional comments that the CVA deems necessary.
§ 250.918
What are the CVA's primary duties during the installation phase?
(a) The CVA must use good engineering judgment and practice in conducting an independent assessment of the installation activities.
(b) Primary duties of the CVA during the installation phase include the following:
The CVA must . . . | Operation or equipment to be inspected . . .
(1) Verify, as appropriate | (i) Loadout and initial flotation operations;
| (ii) Towing operations to the specified location, and review the towing records;
| (iii) Launching and uprighting operations;
| (iv) Submergence operations;
| (v) Pile or anchor installations;
| (vi) Installation of mooring and tethering systems;
| (vii) Final deck and component installations; and
| (viii) Installation at the approved location according to the approved design and the installation plan.
(2) Witness (for a fixed or floating platform) | (i) The loadout of the jacket, decks, piles, or structures from each fabrication site;
| (ii) The actual installation of the platform or major modification and the related installation activities.
(3) Witness (for a floating platform) | (i) The loadout of the platform;
| (ii) The installation of drilling, production, and pipeline risers, and riser tensioning systems (at least for the initial installation of these elements);
| (iii) The installation of turrets and turret-and-hull interfaces;
| (iv) The installation of foundation pilings and templates, and anchoring systems; and
| (v) The installation of the mooring and tethering systems.
(4) Conduct an onsite survey | Survey the platform after transportation to the approved location.
| (5) Spot-check as necessary to determine compliance with the applicable documents listed in § 250.901(a); the alternative codes, rules and standards approved under 250.901(b); the requirements listed in § 250.903 and § 250.906 through 250.908 of this subpart and the approved plans | (i) Equipment; (ii) Procedures; and (iii) Recordkeeping.
(c) Reports. The CVA must submit interim reports to you and the Regional Supervisor, as appropriate. The CVA must prepare a final report covering the adequacy of the entire installation phase, and submit one copy of the final report to the Regional Supervisor within 30 days of the installation of the platform. In the final report, the CVA must:
(1) Give details of how, by whom, and when the independent monitoring activities were conducted;
(2) Describe the CVA's activities during the verification process;
(3) Summarize the CVA's findings;
(4) Write a confirmation or denial of compliance with the approved installation plan;
(5) Provide a recommendation to accept or reject the installation; and
(6) Provide any additional comments that the CVA deems necessary.

Inspection, Maintenance, and Assessment of Platforms
§ 250.919
What in-service inspection requirements must I meet?
(a) You must develop a comprehensive annual in-service inspection plan covering all of your platforms. As a minimum, your plan must address the recommendations of the appropriate documents listed in § 250.901(a). Your plan must specify the type, extent, and frequency of in-place inspections which you will conduct for both the above water and the below water structure of all platforms, and pertinent components of the mooring systems for floating platforms. The plan must also address how you are monitoring the corrosion protection for both the above water and below water structure.
(b) You must submit a report annually on November 1 to the Regional Supervisor that must include:
(1) A list of fixed or floating platforms inspected in the preceding 12 months;
(2) The extent and area of inspection;
(3) The type of inspection employed, (i.e., visual, magnetic particle, ultrasonic testing); and
(4) A summary of the testing results indicating what repairs, if any, were needed and the overall structural condition of the fixed or floating platform.
§ 250.920
What are the MMS requirements for assessment of platforms?
(a) You must perform a platform assessment when needed, based on the platform assessment initiators listed in sections 17.2.1-17.2.5 of API RP 2A-WSD, Recommended Practice for Planning, Designing and Constructing Fixed Offshore Platforms—Working Stress Design (incorporated by reference as specified in 30 CFR 250.198).
(b) You must initiate mitigation actions for platforms that do not pass the assessment process of API RP 2A-WSD.
(c) You must document all wells, equipment, and pipelines supported by the platform if you intend to use the medium or low consequence of failure exposure category for your assessment. Exposure categories are defined in API RP 2A-WSD Section 1.7.
(d) MMS may require you to conduct a platform assessment where reduced environmental loading criteria are not allowed.
(e) The use of Section 17, Assessment of Existing Platforms, of API RP 2A-WSD, is limited to existing fixed structures that are serving their original approved purpose.
§ 250.921
How do I analyze my platform for cumulative fatigue?
(a) If you are required to analyze cumulative fatigue on your platform because of the results of an inspection or platform assessment, you must ensure that the safety factors for critical elements listed in § 250.908 are met or exceeded.
(b) If the calculated life of a joint or member does not meet the criteria of § 250.908, you must either mitigate the load, strengthen the joint or member, or develop an increased inspection process.

Subpart J—Pipelines and Pipeline Rights-of-Way
§ 250.1000
General requirements.
(a) Pipelines and associated valves, flanges, and fittings shall be designed, installed, operated, maintained, and abandoned to provide safe and pollution-free transportation of fluids in a manner which does not unduly interfere with other uses in the Outer Continental Shelf (OCS).
(b) An application must be accompanied by payment of the service fee listed in § 250.125 and submitted to the Regional Supervisor and approval obtained before:
(1) Installation, modification, or abandonment of a lease term pipeline;
(2) Installation or modification of a right-of-way (other than lease term) pipeline; or
(3) Modification or relinquishment of a pipeline right-of way.
(c)(1) Department of the Interior (DOI) pipelines, as defined in § 250.1001, must meet the requirements in §§ 250.1000 through 250.1008.
(2) A pipeline right-of-way grant holder must identify in writing to the Regional Supervisor the operator of any pipeline located on its right-of-way, if the operator is different from the right-of-way grant holder.
(3) A producing operator must identify for its own records, on all existing pipelines located on its lease or right-of-way, the specific points at which operating responsibility transfers to a transporting operator.
(i) Each producing operator must, if practical, durably mark all of its above-water transfer points by April 14, 1999 or the date a pipeline begins service, whichever is later.
(ii) If it is not practical to durably mark a transfer point, and the transfer point is located above water, then the operator must identify the transfer point on a schematic located on the facility.
(iii) If a transfer point is located below water, then the operator must identify the transfer point on a schematic and provide the schematic to MMS upon request.
(iv) If adjoining producing and transporting operators cannot agree on a transfer point by April 14, 1999, the MMS Regional Supervisor and the Department of Transportation (DOT) Office of Pipeline Safety (OPS) Regional Director may jointly determine the transfer point.
(4) The transfer point serves as a regulatory boundary. An operator may write to the MMS Regional Supervisor to request an exception to this requirement for an individual facility or area. The Regional Supervisor, in consultation with the OPS Regional Director and affected parties, may grant the request.
(5) Pipeline segments designed, constructed, maintained, and operated under DOT regulations but transferring to DOI regulation as of October 16, 1998, may continue to operate under DOT design and construction requirements until significant modifications or repairs are made to those segments. After October 16, 1998, MMS operational and maintenance requirements will apply to those segments.
(6) Any producer operating a pipeline that crosses into State waters without first connecting to a transporting operator's facility on the OCS must comply with this subpart. Compliance must extend from the point where hydrocarbons are first produced, through and including the last valve and associated safety equipment (e.g., pressure safety sensors) on the last production facility on the OCS.
(7) Any producer operating a pipeline that connects facilities on the OCS must comply with this subpart.
(8) Any operator of a pipeline that has a valve on the OCS downstream (landward) of the last production facility may ask in writing that the MMS Regional Supervisor recognize that valve as the last point MMS will exercise its regulatory authority.
(9) A pipeline segment is not subject to MMS regulations for design, construction, operation, and maintenance if:
(i) It is downstream (generally shoreward) of the last valve and associated safety equipment on the last production facility on the OCS; and
(ii) It is subject to regulation under 49 CFR parts 192 and 195.
(10) DOT may inspect all upstream safety equipment (including valves, over-pressure protection devices, cathodic protection equipment, and pigging devices, etc.) that serve to protect the integrity of DOT-regulated pipeline segments.
(11) OCS pipeline segments not subject to DOT regulation under 49 CFR parts 192 and 195 are subject to all MMS regulations.
(12) A producer may request that its pipeline operate under DOT regulations governing pipeline design, construction, operation, and maintenance.
(i) The operator's request must be in the form of a written petition to the MMS Regional Supervisor that states the justification for the pipeline to operate under DOT regulation.
(ii) The Regional Supervisor will decide, on a case-by-case basis, whether to grant the operator's request. In considering each petition, the Regional Supervisor will consult with the Office of Pipeline Safety (OPS) Regional Director.
(13) A transporter who operates a pipeline regulated by DOT may request to operate under MMS regulations governing pipeline operation and maintenance. Any subsequent repairs or modifications will also be subject to MMS regulations governing design and construction.
(i) The operator's request must be in the form of a written petition to the OPS Regional Director and the MMS Regional Supervisor.
(ii) The MMS Regional Supervisor and the OPS Regional Director will decide how to act on this petition.
(d) A pipeline which qualifies as a right-of-way pipeline (see § 250.1001, Definitions) shall not be installed until a right-of-way has been requested and granted in accordance with this subpart.
(e)(1) The Regional Supervisor may suspend any pipeline operation upon a determination by the Regional Supervisor that continued activity would threaten or result in serious, irreparable, or immediate harm or damage to life (including fish and other aquatic life), property, mineral deposits, or the marine, coastal, or human environment.
(2) The Regional Supervisor may also suspend pipeline operations or a right-of-way grant if the Regional Supervisor determines that the lessee or right-of-way holder has failed to comply with a provision of the Act or any other applicable law, a provision of these or other applicable regulations, or a condition of a permit or right-of-way grant.
(3) The Secretary of the Interior (Secretary) may cancel a pipeline permit or right-of-way grant in accordance with 43 U.S.C. 1334(a)(2). A right-of-way grant may be forfeited in accordance with 43 U.S.C. 1334(e).
[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 63 FR 34597, June 25, 1998; 63 FR 43880, Aug. 17, 1998; 65 FR 46095, July 27, 2000; 71 FR 40912, July 19, 2006]
§ 250.1001
Definitions.
Terms used in this subpart shall have the meanings given below:
DOI pipelines include:
(1) Producer-operated pipelines extending upstream (generally seaward) from each point on the OCS at which operating responsibility transfers from a producing operator to a transporting operator;
(2) Producer-operated pipelines extending upstream (generally seaward) of the last valve (including associated safety equipment) on the last production facility on the OCS that do not connect to a transporter-operated pipeline on the OCS before crossing into State waters;
(3) Producer-operated pipelines connecting production facilities on the OCS;
(4) Transporter-operated pipelines that DOI and DOT have agreed are to be regulated as DOI pipelines; and
(5) All OCS pipelines not subject to regulation under 49 CFR parts 192 and 195.
DOT pipelines include:
(1) Transporter-operated pipelines currently operated under DOT requirements governing design, construction, maintenance, and operation;
(2) Producer-operated pipelines that DOI and DOT have agreed are to be regulated under DOT requirements governing design, construction, maintenance, and operation; and
(3) Producer-operated pipelines downstream (generally shoreward) of the last valve (including associated safety equipment) on the last production facility on the OCS that do not connect to a transporter-operated pipeline on the OCS before crossing into State waters and that are regulated under 49 CFR parts 192 and 195.
Lease term pipelines are those pipelines owned and operated by a lessee or operator and are wholly contained within the boundaries of a single lease, unitized leases, or contiguous (not cornering) leases of that lessee or operator.
Out-of-service pipelines are those pipelines that have not been used to transport oil, natural gas, sulfur, or produced water for more than 30 consecutive days.
Pipelines are the piping, risers, and appurtenances installed for the purpose of transporting oil, gas, sulphur, and produced water. (Piping confined to a production platform or structure is covered in Subpart H, Production Safety Systems, and is excluded from this subpart.)
Production facilities means OCS facilities that receive hydrocarbon production either directly from wells or from other facilities that produce hydrocarbons from wells. They may include processing equipment for treating the production or separating it into its various liquid and gaseous components before transporting it to shore.
Right-of-way pipelines are those pipelines which—
(1) Are contained within the boundaries of a single lease or group of unitized leases but are not owned and operated by the lessee or operator of that lease or unit,
(2) Are contained within the boundaries of contiguous (not cornering) leases which do not have a common lessee or operator,
(3) Are contained within the boundaries of contiguous (not cornering) leases which have a common lessee or operator but are not owned and operated by that common lessee or operator, or
(4) Cross any portion of an unleased block(s).
[53 FR 10690, Apr. 1, 1998. Redesignated at 63 FR 29479, May 29, 1998, as amended at 63 FR 43881, Aug. 17, 1998; 65 FR 46096, July 27, 2000; 67 FR 35405, May 17, 2002; 72 FR 25201, May 4, 2007]
§ 250.1002
Design requirements for DOI pipelines.
(a) The internal design pressure for steel pipe shall be determined in accordance with the following formula:
For limitations see section 841.121 of American National Standards Institute (ANSI) B31.8 (incorporated by reference as specified in 30 CFR 250.198) where—
P=Internal design pressure in pounds per square inch (psi).
S=Specified minimum yield strength, in psi, stipulated in the specification under which the pipe was purchased from the manufacturer or determined in accordance with section 811.253(h) of ANSI B31.8.
D=Nominal outside diameter of pipe, in inches.
t=Nominal wall thickness, in inches.
F=Construction design factor of 0.72 for the submerged component and 0.60 for the riser component.
E=Longitudinal joint factor obtained from Table 841.1B of ANSI B31.8. (See also section 811.253(d)).
T=Temperature derating factor obtained from Table 841.1C of ANSI B31.8.
(b)(1) Pipeline valves shall meet the minimum design requirements of American Petroleum Institute (API) Spec 6A, API Spec 6D, or the equivalent. A valve may not be used under operating conditions that exceed the applicable pressure-temperature ratings contained in those standards.
(2) Pipeline flanges and flange accessories shall meet the minimum design requirements of ANSI B16.5, API Spec 6A, or the equivalent (incorporated by reference as specified in 30 CFR 250.198). Each flange assembly must be able to withstand the maximum pressure at which the pipeline is to be operated and to maintain its physical and chemical properties at any temperature to which it is anticipated that it might be subjected in service.
(3) Pipeline fittings shall have pressure-temperature ratings based on stresses for pipe of the same or equivalent material. The actual bursting strength of the fitting shall at least be equal to the computed bursting strength of the pipe.
(4) If you are installing pipelines constructed of unbonded flexible pipe, you must design them according to the standards and procedures of API Spec 17J, incorporated by reference as specified in 30 CFR 250.198.
(5) You must design pipeline risers for tension leg platforms and other floating platforms according to the design standards of API RP 2RD, Design of Risers for Floating Production Systems (FPSs) and Tension Leg Platforms (TLPs), incorporated by reference as specified in 30 CFR 250.198.
(c) The maximum allowable operating pressure (MAOP) shall not exceed the least of the following:
(1) Internal design pressure of the pipeline, valves, flanges, and fittings;
(2) Eighty percent of the hydrostatic pressure test (HPT) pressure of the pipeline; or
(3) If applicable, the MAOP of the receiving pipeline when the proposed pipeline and the receiving pipeline are connected at a subsea tie-in.
(d) If the maximum source pressure (MSP) exceeds the pipeline's MAOP, you must install and maintain redundant safety devices meeting the requirements of section A9 of API RP 14C (incorporated by reference as specified in § 250.198). Pressure safety valves (PSV) may be used only after a determination by the Regional Supervisor that the pressure will be relieved in a safe and pollution-free manner. The setting level at which the primary and redundant safety equipment actuates shall not exceed the pipeline's MAOP.
(e) Pipelines shall be provided with an external protective coating capable of minimizing underfilm corrosion and a cathodic protection system designed to mitigate corrosion for at least 20 years.
(f) Pipelines shall be designed and maintained to mitigate any reasonably anticipated detrimental effects of water currents, storm or ice scouring, soft bottoms, mud slides, earthquakes, subfreezing temperatures, and other environmental factors.
[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998, as amended at 67 FR 51760, Aug. 9, 2002; 70 FR 41583, July 19, 2005; 72 FR 12096, Mar. 15, 2007; 72 FR 25201, May 4, 2007]
§ 250.1003
Installation, testing, and repair requirements for DOI pipelines.
(a)(1) Pipelines greater than 8-5/8 inches in diameter and installed in water depths of less than 200 feet shall be buried to a depth of at least 3 feet unless they are located in pipeline congested areas or seismically active areas as determined by the Regional Supervisor. Nevertheless, the Regional Supervisor may require burial of any pipeline if the Regional Supervisor determines that such burial will reduce the likelihood of environmental degradation or that the pipeline may constitute a hazard to trawling operations or other uses. A trawl test or diver survey may be required to determine whether or not pipeline burial is necessary or to determine whether a pipeline has been properly buried.
(2) Pipeline valves, taps, tie-ins, capped lines, and repaired sections that could be obstructive shall be provided with at least 3 feet of cover unless the Regional Supervisor determines that such items present no hazard to trawling or other operations. A protective device may be used to cover an obstruction in lieu of burial if it is approved by the Regional Supervisor prior to installation.
(3) Pipelines shall be installed with a minimum separation of 18 inches at pipeline crossings and from obstructions.
(4) Pipeline risers installed after April 1, 1988, shall be protected from physical damage that could result from contact with floating vessels. Riser protection on pipelines installed on or before April 1, 1988, may be required when the Regional Supervisor determines that significant damage potential exists.
(b)(1) Pipelines shall be pressure tested with water at a stabilized pressure of at least 1.25 times the MAOP for at least 8 hours when installed, relocated, uprated, or reactivated after being out-of-service for more than 1 year.
(2) Prior to returning a pipeline to service after a repair, the pipeline shall be pressure tested with water or processed natural gas at a minimum stabilized pressure of at least 1.25 times the MAOP for at least 2 hours.
(3) Pipelines shall not be pressure tested at a pressure which produces a stress in the pipeline in excess of 95 percent of the specified minimum-yield strength of the pipeline. A temperature recorder measuring test fluid temperature synchronized with a pressure recorder along with deadweight test readings shall be employed for all pressure testing. When a pipeline is pressure tested, no observable leakage shall be allowed. Pressure gauges and recorders shall be of sufficient accuracy to verify that leakage is not occurring.
(4) The Regional Supervisor may require pressure testing of pipelines to verify the integrity of the system when the Regional Supervisor determines that there is a reasonable likelihood that the line has been damaged or weakened by external or internal conditions.
(c) When a pipeline is repaired utilizing a clamp, the clamp shall be a full encirclement clamp able to withstand the anticipated pipeline pressure.
[53 FR 10690, Apr. 1, 1988; 53 FR 12227, Apr. 13, 1988; 57 FR 26997, June 17, 1992. Redesignated at 63 FR 29479, May 29, 1998, as amended at 72 FR 25201, May 4, 2007]
§ 250.1004
Safety equipment requirements for DOI pipelines.
(a) The lessee shall ensure the proper installation, operation, and maintenance of safety devices required by this section on all incoming, departing, and crossing pipelines on platforms.
(b)(1)(i) Incoming pipelines to a platform shall be equipped with a flow safety valve (FSV).
(ii) For sulphur operations, incoming pipelines delivering gas to the power plant platform may be equipped with high- and low-pressure sensors (PSHL), which activate audible and visual alarms in lieu of requirements in paragraph (b)(1)(i) of this section. The PSHL shall be set at 15 percent or 5 psi, whichever is greater, above and below the normal operating pressure range.
(2) Incoming pipelines boarding a production platform shall be equipped with an automatic shutdown valve (SDV) immediately upon boarding the platform. The SDV shall be connected to the automatic- and remote-emergency shut-in systems.
(3) Departing pipelines receiving production from production facilities shall be protected by high- and low-pressure sensors (PSHL) to directly or indirectly shut in all production facilities. The PSHL shall be set not to exceed 15 percent above and below the normal operating pressure range. However, high pilots shall not be set above the pipeline's MAOP.
(4) Crossing pipelines on production or manned nonproduction platforms which do not receive production from the platform shall be equipped with an SDV immediately upon boarding the platform. The SDV shall be operated by a PSHL on the departing pipelines and connected to the platform automatic- and remote-emergency shut-in systems.
(5) The Regional Supervisor may require that oil pipelines be equipped with a metering system to provide a continuous volumetric comparison between the input to the line at the structure(s) and the deliveries onshore. The system shall include an alarm system and shall be of adequate sensitivity to detect variations between input and discharge volumes. In lieu of the foregoing, a system capable of detecting leaks in the pipeline may be substituted with the approval of the Regional Supervisor.
(6) Pipelines incoming to a subsea tie-in shall be equipped with a block valve and an FSV. Bidirectional pipelines connected to a subsea tie-in shall be equipped with only a block valve.
(7) Gas-lift or water-injection pipelines on unmanned platforms need only be equipped with an FSV installed immediately upstream of each casing annulus or the first inlet valve on the christmas tree.
(8) Bidirectional pipelines shall be equipped with a PSHL and an SDV immediately upon boarding each platform.
(9) Pipeline pumps must comply with section A7 of API RP 14C (incorporated by reference as specified in § 250.198). The setting levels for the PSHL devices are specified in paragraph (b)(3) of this section.
(c) If the required safety equipment is rendered ineffective or removed from service on pipelines which are continued in operation, an equivalent degree of safety shall be provided. The safety equipment shall be identified by the placement of a sign on the equipment stating that the equipment is rendered ineffective or removed from service.
[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1989; 56 FR 32100, July 15, 1991. Redesignated at 63 FR 29479, May 29, 1998; 67 FR 51760, Aug. 9, 2002; 72 FR 25201, May 4, 2007]
§ 250.1005
Inspection requirements for DOI pipelines.
(a) Pipeline routes shall be inspected at time intervals and methods prescribed by the Regional Supervisor for indication of pipeline leakage. The results of these inspections shall be retained for at least 2 years and be made available to the Regional Supervisor upon request.
(b) When pipelines are protected by rectifiers or anodes for which the initial life expectancy of the cathodic protection system either cannot be calculated or calculations indicate a life expectancy of less than 20 years, such pipelines shall be inspected annually by taking measurements of pipe-to-electrolyte potential.
[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998, as amended at 72 FR 25201, May 4, 2007]
§ 250.1006
How must I decommission and take out of service a DOI pipeline?
(a) The requirements for decommissioning pipelines are listed in § 250.1750 through § 250.1754.
(b) The table in this section lists the requirements if you take a DOI pipeline out of service:
If you have the pipeline out of service for: | Then you must:
(1) 1 year or less | Isolate the pipeline with a blind flange or a closed block valve at each end of the pipeline.
(2) More than 1 year but less than 5 years | Flush and fill the pipeline with inhibited seawater.
(3) 5 or more years | Decommission the pipeline according to §§ 250.1750-250.1754.
[67 FR 35405, May 17, 2002]
§ 250.1007
What to include in applications.
(a) Applications to install a lease term pipeline or for a pipeline right-of-way grant must be submitted in quadruplicate to the Regional Supervisor. Right-of-way grant applications must include an identification of the operator of the pipeline. Each application must include the following:
(1) Plat(s) drawn to a scale specified by the Regional Supervisor showing major features and other pertinent data including area, lease, and block designations; water depths; route; length in Federal waters; width of right-of-way, if applicable; connecting facilities; size; product(s) to be transported with anticipated gravity or density; burial depth; direction of flow; X-Y coordinates of key points; and the location of other pipelines that will be connected to or crossed by the proposed pipeline(s). The initial and terminal points of the pipeline and any continuation into State jurisdiction shall be accurately located even if the pipeline is to have an onshore terminal point. A plat(s) submitted for a pipeline right-of-way shall bear a signed certificate upon its face by the engineer who made the map that certifies that the right-of-way is accurately represented upon the map and that the design characteristics of the associated pipeline are in accordance with applicable regulations.
(2) A schematic drawing showing the size, weight, grade, wall thickness, and type of line pipe and risers; pressure-regulating devices (including back-pressure regulators); sensing devices with associated pressure-control lines; PSV's and settings; SDV's, FSV's, and block valves; and manifolds. This schematic drawing shall also show input source(s), e.g., wells, pumps, compressors, and vessels; maximum input pressure(s); the rated working pressure, as specified by ANSI or API, of all valves, flanges, and fittings; the initial receiving equipment and its rated working pressure; and associated safety equipment and pig launchers and receivers. The schematic must indicate the point on the OCS at which operating responsibility transfers between a producing operator and a transporting operator.
(3) General information as follows:
(i) Description of cathodic protection system. If pipeline anodes are to be used, specify the type, size, weight, number, spacing, and anticipated life;
(ii) Description of external pipeline coating system;
(iii) Description of internal protective measures;
(iv) Specific gravity of the empty pipe;
(v) MSP;
(vi) MAOP and calculations used in its determination;
(vii) Hydrostatic test pressure, medium, and period of time that the line will be tested;
(viii) MAOP of the receiving pipeline or facility,
(ix) Proposed date for commencing installation and estimated time for construction; and
(x) Type of protection to be afforded crossing pipelines, subsea valves, taps, and manifold assemblies, if applicable.
(4) The application must include a description of any additional design precautions which will be taken to enable the pipeline to withstand the effects of water currents, storm or ice scouring, soft bottoms, mudslides, earthquakes, permafrost, and other environmental factors. If your application involves using unbonded flexible pipe, you must:
(i) Review the manufacturer's Design Methodology Verification Report, and the independent verification agent's (IVA's) certificate for the design methodology contained in that report, to ensure that the manufacturer has complied with the requirements of API Spec 17J incorporated by reference as specified in 30 CFR 250.198;
(ii) Determine that the unbonded flexible pipe is suitable for its intended purpose on the lease or pipeline right-of-way;
(iii) Submit to the MMS Regional Supervisor the manufacturer's design specifications for the unbonded flexible pipe; and
(iv) Submit to the MMS Regional Supervisor a statement certifying that the pipe is suitable for its intended use, and that the manufacturer has complied with the IVA requirements of API Spec 17J incorporated by reference as specified in 30 CFR 250.198.
(5) The application shall include a shallow hazards survey report and, if required by the Regional Director, an archaeological resource report that covers the entire length of the pipeline. A shallow hazards analysis may be included in a lease term pipeline application in lieu of the shallow hazards survey report with the approval of the Regional Director. The Regional Director may require the submission of the data upon which the report or analysis is based.
(b) Applications to modify an approved lease term pipeline or right-of-way grant shall be submitted in quadruplicate to the Regional Supervisor. These applications need only address those items in the original application affected by the proposed modification.
[53 FR 10690, Apr. 1, 1988, as amended at 59 FR 53094, Oct. 21, 1994. Redesignated at 63 FR 29479, May 29, 1998, as amended at 63 FR 43881, Aug. 17, 1998; 67 FR 35406, May 17, 2002; 70 FR 41583, July 19, 2005; 72 FR 25201, May 4, 2007]
§ 250.1008
Reports.
(a) The lessee, or right-of-way holder, shall notify the Regional Supervisor at least 48 hours prior to commencing the installation or relocation of a pipeline or conducting a pressure test on a pipeline.
(b) The lessee or right-of-way holder shall submit a report to the Regional Supervisor within 90 days after completion of any pipeline construction. The report, submitted in triplicate, shall include an “as-built” location plat drawn to a scale specified by the Regional Supervisor showing the location, length in Federal waters, and X-Y coordinates of key points; the completion date; the proposed date of first operation; and the HPT data. Pipeline right-of-way “as-built” location plats shall be certified by a registered engineer or land surveyor and show the boundaries of the right-of-way as granted. If there is a substantial deviation of the pipeline route as granted in the right-of-way, the report shall include a discussion of the reasons for such deviation.
(c) The lessee or right-of-way holder shall report to the Regional Supervisor any pipeline taken out of service. If the period of time in which the pipeline is out of service is greater than 60 days, written confirmation is also required.
(d) The lessee or right-of-way holder shall report to the Regional Supervisor when any required pipeline safety equipment is taken out of service for more than 12 hours. The Regional Supervisor shall be notified when the equipment is returned to service.
(e) The lessee or right-of-way holder must notify the Regional Supervisor before the repair of any pipeline or as soon as practicable. Your notification must be accompanied by payment of the service fee listed in § 250.125. You must submit a detailed report of the repair of a pipeline or pipeline component to the Regional Supervisor within 30 days after the completion of the repairs. In the report you must include the following:
(1) Description of repairs;
(2) Results of pressure test; and
(3) Date returned to service.
(f) The Regional Supervisor may require that DOI pipeline failures be analyzed and that samples of a failed section be examined in a laboratory to assist in determining the cause of the failure. A comprehensive written report of the information obtained shall be submitted by the lessee to the Regional Supervisor as soon as available.
(g) If the effects of scouring, soft bottoms, or other environmental factors are observed to be detrimentally affecting a pipeline, a plan of corrective action shall be submitted to the Regional Supervisor for approval within 30 days of the observation. A report of the remedial action taken shall be submitted to the Regional Supervisor by the lessee or right-of-way holder within 30 days after completion.
(h) The results and conclusions of measurements of pipe-to-electrolyte potential measurements taken annually on DOI pipelines in accordance with § 250.1005(b) of this part shall be submitted to the Regional Supervisor by the lessee before March of each year.
[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 71 FR 40912, July 19, 2006]
§ 250.1009
Requirements to obtain pipeline right-of-way grants.
(a) In addition to applicable requirements of §§ 250.1000 through 250.1008 and other regulations of this part, regulations of the Department of Transportation, Department of the Army, and the Federal Energy Regulatory Commission (FERC), when a pipeline qualifies as a right-of-way pipeline, the pipeline shall not be installed until a right-of-way has been requested and granted in accordance with this subpart. The right-of-way grant is issued pursuant to 43 U.S.C. 1334(e) and may be acquired and held only by citizens and nationals of the United States; aliens lawfully admitted for permanent residence in the United States as defined in 8 U.S.C. 1101(a)(20); private, public, or municipal corporations organized under the laws of the United States or territory thereof, the District of Columbia, or of any State; or associations of such citizens, nationals, resident aliens, or private, public, or municipal corporations, States, or political subdivisions of States.
(b) A right-of-way shall include the site on which the pipeline and associated structures are to be situated, shall not exceed 200 feet in width unless safety and environmental factors during construction and operation of the associated right-of-way pipeline require a greater width, and shall be limited to the area reasonably necessary for pumping stations or other accessory structures.
[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1989; 55 FR 47753, Nov. 15, 1990; 59 FR 53094, Oct. 21, 1994; 62 FR 27955, May 22, 1997. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 63 FR 34597, June 25, 1998; 64 FR 9065, Feb. 24, 1999. Further redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003]
§ 250.1010
General requirements for pipeline right-of-way holders.
An applicant, by accepting a right-of-way grant, agrees to comply with the following requirements:
(a) The right-of-way holder shall comply with applicable laws and regulations and the terms of the grant.
(b) The granting of the right-of-way shall be subject to the express condition that the rights granted shall not prevent or interfere in any way with the management, administration, or the granting of other rights by the United States, either prior or subsequent to the granting of the right-of-way. Moreover, the holder agrees to allow the occupancy and use by the United States, its lessees, or other right-of-way holders, of any part of the right-of-way grant not actually occupied or necessarily incident to its use for any necessary operations involved in the management, administration, or the enjoyment of such other granted rights.
(c) If the right-of-way holder discovers any archaeological resource while conducting operations within the right-of-way, the right-of-way holder shall immediately halt operations within the area of the discovery and report the discovery to the Regional Director. If investigations determine that the resource is significant, the Regional Director will inform the right-of-way holder how to protect it.
(d) The Regional Supervisor shall be kept informed at all times of the right-of-way holder's address and, if a corporation, the address of its principal place of business and the name and address of the officer or agent authorized to be served with process.
(e) The right-of-way holder shall pay the United States or its lessees or right-of-way holders, as the case may be, the full value of all damages to the property of the United States or its said lessees or right-of-way holders and shall indemnify the United States against any and all liability for damages to life, person, or property arising from the occupation and use of the area covered by the right-of-way grant.
(f)(1) The holder of a right-of-way oil or gas pipeline shall transport or purchase oil or natural gas produced from submerged lands in the vicinity of the pipeline without discrimination and in such proportionate amounts as the FERC may, after a full hearing with due notice thereof to the interested parties, determine to be reasonable, taking into account, among other things, conservation and the prevention of waste.
(2) Unless otherwise exempted by FERC pursuant to 43 U.S.C. 1334(f)(2), the holder shall—
(i) Provide open and nondiscriminatory access to a right-of-way pipeline to both owner and nonowner shippers, and
(ii) Comply with the provisions of 43 U.S.C. 1334(f)(1)(B) under which FERC may order an expansion of the throughput capacity of a right-of-way pipeline which is approved after September 18, 1978, and which is not located in the Gulf of Mexico or the Santa Barbara Channel.
(g) The area covered by a right-of-way and all improvements thereon shall be kept open at all reasonable times for inspection by the Minerals Management Service (MMS). The right-of-way holder shall make available all records relative to the design, construction, operation, maintenance and repair, and investigations on or with regard to such area.
(h) Upon relinquishment, forfeiture, or cancellation of a right-of-way grant, the right-of-way holder shall remove all platforms, structures, domes over valves, pipes, taps, and valves along the right-of-way. All of these improvements shall be removed by the holder within 1 year of the effective date of the relinquishment, forfeiture, or cancellation unless this requirement is waived in writing by the Regional Supervisor. All such improvements not removed within the time provided herein shall become the property of the United States but that shall not relieve the holder of liability for the cost of their removal or for restoration of the site. Furthermore, the holder is responsible for accidents or damages which might occur as a result of failure to timely remove improvements and equipment and restore a site. An application for relinquishment of a right-of- way grant shall be filed in accordance with § 250.1019 of this part.
[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1989; 55 FR 47753, Nov. 15, 1990; 59 FR 53094, Oct. 21, 1994; 62 FR 27955, May 22, 1997. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 63 FR 34597, June 25, 1998; 64 FR 9065, Feb. 24, 1999. Further redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003; 72 FR 25201, May 4, 2007]
§ 250.1011
Bond requirements for pipeline right-of-way holders.
(a) When you apply for, or are the holder of, a right-of-way, you must:
(1) Provide and maintain a $300,000 bond (in addition to the bond coverage required in part 256) that guarantees compliance with all the terms and conditions of the rights-of-way you hold in an OCS area; and
(2) Provide additional security if the Regional Director determines that a bond in excess of $300,000 is needed.
(b) For the purpose of this paragraph, there are three areas:
(1) The Gulf of Mexico and the area offshore the Atlantic Coast;
(2) The areas offshore the Pacific Coast States of California, Oregon, Washington, and Hawaii; and
(3) The area offshore the Coast of Alaska.
(c) If, as the result of a default, the surety on a right-of-way grant bond makes payment to the Government of any indebtedness under a grant secured by the bond, the face amount of such bond and the surety's liability shall be reduced by the amount of such payment.
(d) After a default, a new bond in the amount of $300,000 shall be posted within 6 months or such shorter period as the Regional Supervisor may direct. Failure to post a new bond shall be grounds for forfeiture of all grants covered by the defaulted bond.
[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1989; 55 FR 47753, Nov. 15, 1990; 59 FR 53094, Oct. 21, 1994; 62 FR 27955, May 22, 1997. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 63 FR 34597, June 25, 1998; 64 FR 9065, Feb. 24, 1999. Further redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003; 72 FR 25201, May 4, 2007]
§ 250.1012
Required payments for pipeline right-of-way holders.
(a) You must pay MMS an annual rental of $15 for each statute mile, or part of a statute mile, of the OCS that your pipeline right-of-way crosses.
(b) This paragraph applies to you if you obtain a pipeline right-of-way that includes a site for an accessory to the pipeline, including but not limited to a platform. This paragraph also applies if you apply to modify a right-of-way to change the site footprint. In either case, you must pay the amounts shown in the following table.
If... | Then...
(1) Your accessory site is located in water depths of less than 200 meters; | You must pay a rental of $5 per acre per year with a minimum of $450 per year. The area subject to annual rental includes the areal extent of anchor chains, pipeline risers, and other facilities and devices associated with the accessory.
(2) Your accessory site is located in water depths of 200 meters or greater; | You must pay a rental of $7.50 per acre per year with a minimum of $675 per year. The area subject to annual rental includes the areal extent of anchor chains, pipeline risers, and other facilities and devices associated with the accessory.
(c) If you hold a pipeline right-of-way that includes a site for an accessory to your pipeline and you are not covered by paragraph (b) of this section, then you must pay MMS an annual rental of $75 for use of the affected area.
(d) You may make the rental payments required by paragraphs (a), (b)(1), (b)(2), and (c) of this section on an annual basis, for a 5-year period, or for multiples of 5 years. You must make the first payment at the time you submit the pipeline right-of-way application. You must make all subsequent payments before the respective time periods begin.
(e) Late payments. An interest charge will be assessed on unpaid and underpaid amounts from the date the amounts are due, in accordance with the provisions found in 30 CFR 218.54. If you fail to make a payment that is late after written notice from MMS, MMS may initiate cancellation of the right-of-use grant and easement under 30 CFR 250.1013.
[68 FR 69312, Dec. 12, 2003, as amended at 69 FR 29433, May 24, 2004]
§ 250.1013
Grounds for forfeiture of pipeline right-of-way grants.
Failure to comply with the Act, regulations, or any conditions of the right-of-way grant prescribed by the Regional Supervisor shall be grounds for forfeiture of the grant in an appropriate judicial proceeding instituted by the United States in any U.S. District Court having jurisdiction in accordance with the provisions of 43 U.S.C. 1349.
[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1989; 55 FR 47753, Nov. 15, 1990; 59 FR 53094, Oct. 21, 1994; 62 FR 27955, May 22, 1997. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 63 FR 34597, June 25, 1998; 64 FR 9065, Feb. 24, 1999. Further redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003]
§ 250.1014
When pipeline right-of-way grants expire.
Any right-of-way granted under the provisions of this subpart remains in effect as long as the associated pipeline is properly maintained and used for the purpose for which the grant was made, unless otherwise expressly stated in the grant. Temporary cessation or suspension of pipeline operations shall not cause the grant to expire. However, if the purpose of the grant ceases to exist or use of the associated pipeline is permanently discontinued for any reason, the grant shall be deemed to have expired.
[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1989; 55 FR 47753, Nov. 15, 1990; 59 FR 53094, Oct. 21, 1994; 62 FR 27955, May 22, 1997. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 63 FR 34597, June 25, 1998; 64 FR 9065, Feb. 24, 1999. Further redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003]
§ 250.1015
Applications for pipeline right-of-way grants.
(a) You must submit an original and three copies of an application for a new or modified pipeline ROW grant to the Regional Supervisor. The application must address those items required by § 250.1007(a) or (b) of this subpart, as applicable. It must also state the primary purpose for which you will use the ROW grant. If the ROW has been used before the application is made, the application must state the date such use began, by whom, and the date the applicant obtained control of the improvement. When you file your application, you must pay the rental required under § 250.1012 of this subpart, as well as the service fees listed in § 250.125 of this part for a pipeline ROW grant to install a new pipeline, or to convert an existing lease term pipeline into a ROW pipeline. An application to modify an approved ROW grant must be accompanied by the additional rental required under § 250.1012 if applicable. You must file a separate application for each ROW.
(b)(1) An individual applicant shall submit a statement of citizenship or nationality with the application. An applicant who is an alien lawfully admitted for permanent residence in the United States shall also submit evidence of such status with the application.
(2) If the applicant is an association (including a partnership), the application shall also be accompanied by a certified copy of the articles of association or appropriate reference to a copy of such articles already filed with MMS and a statement as to any subsequent amendments.
(3) If the applicant is a corporation, the application shall also include the following:
(i) A statement certified by the Secretary or Assistant Secretary of the corporation with the corporate seal showing the State in which it is incorporated and the name of the person(s) authorized to act on behalf of the corporation, or
(ii) In lieu of such a statement, an appropriate reference to statements or records previously submitted to MMS (including material submitted in compliance with prior regulations).
(c) The application shall include a list of every lessee and right-of-way holder whose lease or right-of-way is intersected by the proposed right-of-way. The application shall also include a statement that a copy of the application has been sent by registered or certified mail to each such lessee or right-of-way holder.
(d) The applicant shall include in the application an original and three copies of a completed Nondiscrimination in Employment form (YN 3341-1 dated July 1982). These forms are available at each MMS regional office.
(e) Notwithstanding the provisions of paragraph (a) of this section, the requirements to pay filing fees under that paragraph are suspended until January 3, 2006.
[53 FR 10690, Apr. 1, 1988, as amended at 62 FR 39775, July 24, 1997. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 64 FR 42598, Aug. 5, 1999. Further redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003; 70 FR 49876, Aug. 25, 2005; 70 FR 61893, Oct. 27, 2005]
§ 250.1016
Granting pipeline rights-of-way.
(a) In considering an application for a right-of-way, the Regional Supervisor shall consider the potential effect of the associated pipeline on the human, marine, and coastal environments, life (including aquatic life), property, and mineral resources in the entire area during construction and operational phases. The Regional Supervisor shall prepare an environmental analysis in accordance with applicable policies and guidelines. To aid in the evaluation and determinations, the Regional Supervisor may request and consider views and recommendations of appropriate Federal Agencies, hold public meetings after appropriate notice, and consult, as appropriate, with State agencies, organizations, industries, and individuals. Before granting a pipeline right-of-way, the Regional Supervisor shall give consideration to any recommendation by the intergovernmental planning program, or similar process, for the assessment and management of OCS oil and gas transportation.
(b) Should the proposed route of a right-of-way adjoin and subsequently cross any State submerged lands, the applicant shall submit evidence to the Regional Supervisor that the State(s) so affected has reviewed the application. The applicant shall also submit any comment received as a result of that review. In the event of a State recommendation to relocate the proposed route, the Regional Supervisor may consult with the appropriate State officials.
(c)(1) The applicant shall submit photocopies of return receipts to the Regional Supervisor that indicate the date that each lessee or right-of-way holder referenced in § 250.1015(c) of this part has received a copy of the application. Letters of no objection may be submitted in lieu of the return receipts.
(2) The Regional Supervisor shall not take final action on a right-of-way application until the Regional Supervisor is satisfied that each such lessee or right-of-way holder has been afforded at least 30 days from the date determined in paragraph (c)(1) of this section in which to submit comments.
(d) If a proposed right-of-way crosses any lands not subject to disposition by mineral leasing or restricted from oil and gas activities, it shall be rejected by the Regional Supervisor unless the Federal Agency with jurisdiction over such excluded or restricted area gives its consent to the granting of the right-of-way. In such case, the applicant, upon a request filed within 30 days after receipt of the notification of such rejection, shall be allowed an opportunity to eliminate the conflict.
(e)(1) If the application and other required information are found to be in compliance with applicable laws and regulations, the right-of-way may be granted. The Regional Supervisor may prescribe, as conditions to the right-of-way grant, stipulations necessary to protect human, marine, and coastal environments, life (including aquatic life), property, and mineral resources located on or adjacent to the right-of-way.
(2) If the Regional Supervisor determines that a change in the application should be made, the Regional Supervisor shall notify the applicant that an amended application shall be filed subject to stipulated changes. The Regional Supervisor shall determine whether the applicant shall deliver copies of the amended application to other parties for comment.
(3) A decision to reject an application shall be in writing and shall state the reasons for the rejection.
[53 FR 10690, Apr. 1, 1988, as amended at 54 FR 50617, Dec. 8, 1988. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998. Further redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003; 72 FR 25201, May 4, 2007]
§ 250.1017
Requirements for construction under pipeline right-of-way grants.
(a) Failure to construct the associated right-of-way pipeline within 5 years of the date of the granting of a right-of-way shall cause the grant to expire.
(b)(1) A right-of-way holder shall ensure that the right-of-way pipeline is constructed in a manner that minimizes deviations from the right-of-way as granted.
(2) If, after constructing the right-of-way pipeline, it is determined that a deviation from the proposed right-of-way as granted has occurred, the right-of-way holder shall—
(i) Notify the operators of all leases and holders of all right-of-way grants in which a deviation has occurred, and within 60 days of the date of the acceptance by the Regional Supervisor of the completion of pipeline construction report, provide the Regional Supervisor with evidence of such notification; and
(ii) Relinquish any unused portion of the right-of-way.
(3) Substantial deviation of a right-of-way pipeline as constructed from the proposed right-of-way as granted may be grounds for forfeiture of the right-of-way.
(c) If the Regional Supervisor determines that a significant change in conditions has occurred subsequent to the granting of a right-of-way but prior to the commencement of construction of the associated pipeline, the Regional Supervisor may suspend or temporarily prohibit the commencement of construction until the right-of-way grant is modified to the extent necessary to address the changed conditions.
[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998. Further redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003]
§ 250.1018
Assignment of pipeline right-of-way grants.
(a) Assignment may be made of a right-of-way grant, in whole or of any lineal segment thereof, subject to the approval of the Regional Supervisor. An application for approval of an assignment of a right-of-way or of a lineal segment thereof, shall be filed in triplicate with the Regional Supervisor.
(b) Any application for approval for an assignment, in whole or in part, of any right, title, or interest in a right-of-way grant must be accompanied by the same showing of qualifications of the assignees as is required of an applicant for a ROW in § 250.1015 of this subpart and must be supported by a statement that the assignee agrees to comply with and to be bound by the terms and conditions of the ROW grant. The assignee must satisfy the bonding requirements in § 250.1011 of this subpart. No transfer will be recognized unless and until it is first approved, in writing, by the Regional Supervisor. The assignee must pay the service fee listed in § 250.125 of this part for a pipeline ROW assignment request.
(c) Notwithstanding the provisions of paragraph (b) of this section, the requirement to pay a filing fee under that paragraph is suspended until January 3, 2006.
[53 FR 10690, Apr. 1, 1988, as amended at 62 FR 39775, July 24, 1997. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998. Further redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003; 70 FR 49876, Aug. 25, 2005; 70 FR 61893, Oct. 27, 2005]
§ 250.1019
Relinquishment of pipeline right-of-way grants.
A right-of-way grant or a portion thereof may be surrendered by the holder by filing a written relinquishment in triplicate with the Regional Supervisor. It must contain those items addressed in §§ 250.1751 and 250.1752 of this part. A relinquishment shall take effect on the date it is filed subject to the satisfaction of all outstanding debts, fees, or fines and the requirements in § 250.1010(h) of this part.
[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 67 FR 35406, May 17, 2002. Further redesignated and amended at 68 FR 69311, 69312, Dec. 12, 2003; 72 FR 25201, May 4, 2007]

Subpart K—Oil and Gas Production Rates
§ 250.1100
Definitions for production rates.
Terms used in this subpart shall have meanings given below:
Enhanced recovery operations means pressure maintenance operations, secondary and tertiary recovery, cycling, and similar recovery operations which alter the natural forces in a reservoir to increase the ultimate recovery of oil or gas.
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 gas cap of an oil reservoir with an associated gas cap.
Maximum Efficient Rate (MER) means the maximum sustainable daily oil or gas withdrawal rate from a reservoir which 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.
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.
Sensitive reservoir means a reservoir in which ultimate recovery is decreased by high reservoir production rates. A high reservoir production rate is one which exceeds the MER.
Waste of oil and gas means: (1) The physical waste of oil and gas; (2) the inefficient, excessive, or improper use of, or the unnecessary dissipation of reservoir energy; (3) the locating, spacing, drilling, equipping, operating, or producing of any oil or gas well(s) in a manner which causes or tends to cause a reduction in the quantity of oil or gas ultimately recoverable from a pool under prudent and proper operations or which causes or tends to cause unnecessary or excessive surface loss or destruction of oil or gas; or (4) the inefficient storage of oil.
§ 250.1101
General requirements and classification of reservoirs.
(a) Wells and reservoirs shall be produced at rates that will provide economic development and depletion of the hydrocarbon resources in a manner that would maximize the ultimate recovery without adversely affecting correlative rights.
(b) For directionally drilled wells in which the completed interval is closer than 500 feet from a unit or lease line or for vertically drilled wells in which the surface location is closer than 500 feet from a unit or lease line, for which the unit, lease, or royalty interests are not the same, the prior approval by the Regional Supervisor is required before production is commenced. An operator requesting such an approval shall furnish the Regional Supervisor with letters expressing acceptance or objection from operators of offset properties.
(c) The lessee shall propose a classification for each reservoir as an oil reservoir, an oil reservoir with an associated gas cap or a gas reservoir, and as sensitive or nonsensitive.
(d) All oil reservoirs with associated gas caps shall be initially classified as sensitive and shall require establishing a maximum efficient production rate and balancing of production in accordance with § 250.1102(a) (1) and (5) of this part. All other oil reservoirs and all gas reservoirs shall be initially classified as nonsensitive.
(e) A reservoir may be reclassified by the Minerals Management Service (MMS) as to type and sensitivity at any time during its productive life when information becomes available showing that reclassification is warranted.
(f) The lessee must pay the service fee listed in § 250.125 of this part with its request for either a 500 feet from lease/unit line production interval or to produce from a completion in an associated gas cap of a sensitive reservoir under this section.
[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 70 FR 49876, Aug. 25, 2005]
§ 250.1102
Oil and gas production rates.
(a) MER. (1) The lessee shall submit a proposed MER for each producing sensitive reservoir on Form MMS-127, Sensitive Reservoir Information Report (SRI), along with appropriate supporting information to the Regional Supervisor within 45 days after discovering that a reservoir is sensitive.
(2) The lessee may propose to revise an MER by submitting Form MMS-127 with appropriate supporting information.
(3) The effective date of an MER for a reservoir or revision thereof shall be the first day of the month in which Form MMS-127 is submitted.
(4) When approved, the MER shall not be exceeded, except as provided in paragraph (a)(5) of this section.
(5) If a reservoir is produced at a rate in excess of the MER for any month, the lessee should initiate measures necessary to balance production (offset overproduction by underproduction) during the next succeeding month. All overproduction shall be balanced by the end of the next succeeding calendar quarter following the quarter in which the overproduction occurred. Any operation in an overproduction status in any reservoir for two successive calendar quarters shall be shut in from that reservoir until the actual production is equal to that which would have occurred under the approved MER, unless an alternative plan is approved by the Regional Supervisor.
(6) The lessee shall review the MER for each producing sensitive reservoir at least once a year and submit Form MMS-127 with appropriate supporting information.
(7) The lessee may request the reclassification of a reservoir from sensitive to nonsensitive and request approval for termination of an MER by submitting Form MMS-127 with information supporting the reclassification and termination.
(8) At the request of the Regional Supervisor, the lessee shall furnish the information specified on Form MMS-127 for any producing nonsensitive reservoir.
(9) Public information copies of Form MMS-127 shall be submitted in accordance with § 250.186.
(b) MPR. (1) The lessee shall propose an MPR for each producing well completion together with full information on the method used in its determination. The MPR shall be based on well tests and any limitations imposed by well and surface equipment, sand production, gas-oil and water-oil ratios, location of perforated intervals, and prudent operating practices. The sum of the MPR's of wells completed in a sensitive reservoir shall not exceed the approved MER.
(2) The lessee shall conduct a well-flow potential test within 30 days of the date of first continuous production on all new, recompleted, and reworked well completions. Within 15 days after the end of the test period, the lessee must submit a proposed MPR with well potential test for the individual well completion on Form MMS-126, Well Potential Test Report. The initial MPR shall not exceed 110 percent of the test rate submitted and shall be effective on the first day of the month following the end of the test period if approved by the Regional Supervisor. During the 30-day period allowed for testing, the lessee may produce a new, recompleted, or reworked completion at rates necessary to establish the MPR. After the 30-day period and prior to approval of the initial MPR, a well completion may be produced at a rate not to exceed the proposed rate. The lessee shall report the total production obtained during the test period and shall identify all other wells completed in the reservoir on Form MMS-126.
(3) At least one well test shall be conducted during a calendar half for producing oil-well and gas-well completions and results submitted on Form MMS-128, Semiannual Well Test Report. Well tests shall be submitted within 45 days of the day the test was conducted.
(4) Unless otherwise ordered by the Regional Supervisor, a revised MPR shall automatically be approved for each well completion for each well test submitted equal to 110 percent of the test rate. The revised MPR will be effective on the first day of the month following the date the well test was conducted. Prior to the approval of a proposed increase of the MPR, a well completion may be produced at a rate not to exceed the proposed increased rate.
(5) When a well test is not submitted during a calendar half for a producing oil-well or gas-well completion, the MPR will be automatically canceled effective on the first day of the appropriate following calendar half.
(6) When the results of a semiannual well test for an oil-well or gas-well completion cannot be submitted within the specified time, the lessee shall request an extension of time for submitting those test results. The extension must be approved in advance by the Regional Supervisor to continue production under the last approved MPR.
(7) When approved by the Regional Supervisor, an MPR shall not be exceeded, except as provided in paragraphs (b)(4) and (c) of this section.
(8) Public Information copies of Form MMS-126 shall be submitted in accordance with § 250.186.
(9) Public information copies of Form MMS-128 shall be submitted in accordance with § 250.186.
(c) Temporary rates. Temporary production rates resulting from normal variations and fluctuations exceeding a well MPR or reservoir MER shall not be considered a violation, provided that such production in excess of an approved MER is balanced by production in accordance with the provisions of paragraph (a)(5) of this section.
[53 FR 10690, Apr. 1, 1988, as amended at 58 FR 49928, Sept. 24, 1993. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 64 FR 72794, Dec. 28, 1999; 65 FR 2875, Jan. 19, 2000; 71 FR 19646, Apr. 17, 2006; 72 FR 25201, May 4, 2007]
§ 250.1103
Well production testing.
(a) The required well testing shall be conducted for a period of not less than four consecutive hours. Immediately prior to the 4-hour test period, the well completion shall have produced under stabilized conditions for a period of not less than six consecutive hours. The 6-hour pretest period shall not begin until after the recovery of a volume of fluid equivalent to the amount of fluids introduced into the formation during completion, recompletion, reworking, or treatment operations. Measured gas volumes shall be adjusted to the standard conditions of 14.73 pounds per square inch absolute (psia) and 60 °F for all tests. When orifice meters are used, a specific gravity for the gas shall be obtained or estimated, and a specific gravity-correction factor shall be applied to the orifice coefficient. The Regional Supervisor may require a prolonged test or retest of a well completion if the test is determined to be necessary for the establishment of a well MPR or a reservoir MER. The Regional Supervisor may approve test periods of less than 4 hours and pretest stabilization periods of less than 6 hours for well completions provided that test reliability can be demonstrated under such procedures.
(b) At the request of the Regional Supervisor, the lessee shall conduct a multipoint back-pressure test to determine the theoretical open-flow potential of a gas well. The test shall be conducted within 30 days of the Regional Supervisor's request or within the time period specified by the Regional Supervisor.
(c) An MMS representative may witness any well test of oil-well and gas-well completions. Upon request, a lessee shall provide advance notice to the Regional Supervisor of the time and date of well tests.
[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998, as amended at 72 FR 25201, May 4, 2007]
§ 250.1104
Bottomhole pressure survey.
(a) For each new reservoir, the lessee shall conduct a static bottomhole pressure survey within 3 months after the date of first continuous production.
(b) For each producing reservoir with three or more producing completions, the lessee shall conduct annual static bottomhole pressure surveys in a sufficient number of key wells to establish an average reservoir pressure. The Regional Supervisor may require that a survey be performed on specific wells.
(c) The results of all static bottomhole pressure surveys obtained by the lessee shall be filed with the Regional Supervisor within 60 days after the date of the survey.
§ 250.1105
Flaring or venting gas and burning liquid hydrocarbons.
(a) Lessees may flare or vent oil-well gas or gas-well gas without receiving prior approval from the Regional Supervisor only in the following situations:
(1) When gas vapors are flared or vented in small volumes from storage vessels or other low-pressure production vessels and cannot be economically recovered.
(2) During an equipment failure or to relieve system pressures. The lessee must comply with the following conditions:
(i) Lessees must not flare or vent oil-well gas for more than 48 continuous hours unless the Regional Supervisor approves. The Regional Supervisor may specify a limit of less than 48 hours to prevent air quality degradation.
(ii) Lessees must not flare or vent gas from a facility for more than 144 cumulative hours during any calendar month unless the Regional Supervisor approves.
(iii) Lessees must not flare or vent gas-well gas beyond the time required to eliminate an emergency unless the Regional Supervisor approves.
(3) During the unloading or cleaning of a well, drill-stem testing, production testing, or other well-evaluation testing. Flaring or venting must not exceed 48 cumulative hours per testing operation on a single completion. The Regional Supervisor may allow less time to prevent air quality degradation or more time if lessees need additional time to evaluate reservoir parameters.
(b) Lessees may flare or vent oil-well gas for up to 1 year when the Regional Supervisor approves the request for one of the following reasons:
(1) The lessee initiated an action which, when completed, will eliminate flaring and venting; or
(2) The lessee submitted an evaluation supported by engineering, geologic, and economic data indicating that either:
(i) The oil and gas produced from the well(s) will not economically support the facilities necessary to save and/or sell the gas; or
(ii) There is not enough gas to market.
(c) Lessees may burn produced liquid hydrocarbons only if the Regional Supervisor approves. To burn produced liquid hydrocarbons, the lessee must demonstrate that the amounts to burn would be minimal, or that the alternatives are infeasible or pose a significant risk that may harm offshore personnel or the environment. Alternatives to burning liquid hydrocarbons include transporting the liquids or storing and re-injecting them into a producible zone.
(d) Lessees must prepare records detailing gas flaring or venting and liquid hydrocarbon burning for each facility. The records must include, at a minimum:
(1) Daily volumes of gas flared or vented and liquid hydrocarbons burned;
(2) Number of hours of flaring, venting, or burning on a daily basis;
(3) Reasons for flaring, venting, or burning; and
(4) A list of the wells contributing to flaring, venting, or burning, along with the gas-oil ratio data.
(e) Lessees must keep these records for at least 2 years. Lessees must allow Minerals Management Service representatives to inspect the records at the lessees' field office that is nearest the Outer Continental Shelf facility, or at another location agreed to by the Regional Supervisor. If the Regional Supervisor requests to see the records, lessees must provide a copy.
(f) Requirements for flaring and venting of gas containing H 2 S—(1) Flaring of gas containing H 2 S. (i) The Regional Supervisor may, for safety or air pollution prevention purposes, further restrict the flaring of gas containing H2S. The Regional Supervisor will use information provided in the lessee's H2S Contingency Plan (§ 250.490(f)), Exploration Plan or Development and Production Plan, and associated documents in determining the need for such restrictions.
(ii) If the Regional Supervisor determines that flaring at a facility or group of facilities may significantly affect the air quality of an onshore area, the Regional Supervisor may require the operator(s) to conduct an air quality modeling analysis to determine the potential effect of facility emissions on onshore ambient concentrations of SO2. The Regional Supervisor may require monitoring and reporting or may restrict or prohibit flaring pursuant to §§ 250.303 and 250.304.
(2) Venting of gas containing H 2 S. You must not vent gas containing H2S except for minor releases during maintenance and repair activities that do not result in a 15-minute time weighted average atmospheric concentration of H2S of 20 ppm or higher anywhere on the platform.
(3) Reporting flared gas containing H 2 S. In addition to the recordkeeping requirements of paragraphs (d) and (e) of this section, when required by the Regional Supervisor, the operator must submit to the Regional Supervisor a monthly report of flared and vented gas containing H2S. The report must contain the following information:
(i) On a daily basis, the volume and duration of each flaring episode;
(ii) H2S concentration in the flared gas; and
(iii) Calculated amount of SO2 emitted.
[61 FR 25148, May 20, 1996, as amended at 62 FR 3800, Jan. 27, 1997. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 68 FR 8435, Feb. 20, 2003]
§ 250.1106
Downhole commingling.
(a) An application to commingle hydrocarbons produced from multiple reservoirs within a common wellbore shall be submitted to the Regional Supervisor for approval and shall include all pertinent well information, geologic and reservoir engineering data, and a schematic diagram of well equipment. The application shall provide the estimated recoverable reserves as well as any available alternate drainage points which might be used to produce the reservoirs separately.
(b) For a competitive reservoir, notice of intent to submit the application shall be sent by the applicant to all other lessees having an interest in the reservoir prior to submitting the application to the Regional Supervisor.
(c) The application shall specify the well-completion number to be used for subsequent reporting purposes.
(d) The applicant must pay the service fee listed in § 250.125 of this part with its request for downhole commingling.
[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998, as amended at 70 FR 49876, Aug. 25, 2005]
§ 250.1107
Enhanced oil and gas recovery operations.
(a) The lessee shall timely initiate enhanced oil and gas recovery operations for all competitive and noncompetitive reservoirs where such operations would result in an increased ultimate recovery of oil or gas under sound engineering and economic principles.
(b) A proposed plan for pressure maintenance, secondary and tertiary recovery, cycling, and similar recovery operations to increase the ultimate recovery of oil and/or gas from a reservoir shall be submitted to the Regional Supervisor for approval before such operations are initiated.
(c) Periodic reports of the volumes of oil, gas, or other substances injected, produced, or reproduced shall be submitted as required by the Regional Supervisor.

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

Source:
63 FR 26370, May 12, 1998, unless otherwise noted. Redesignated at 63 FR 29479, May 29, 1998.
§ 250.1200
Question index table.
The table in this section lists questions concerning Oil and Gas Production Measurement, Surface Commingling, and Security.
Frequently asked questions | CFR citation
1. What are the requirements for measuring liquid hydrocarbons? | § 250.1202(a)
2. What are the requirements for liquid hydrocarbon royalty meters? | § 250.1202(b)
3. What are the requirements for run tickets? | § 250.1202(c)
4. What are the requirements for liquid hydrocarbon royalty meter provings? | § 250.1202(d)
5. What are the requirements for calibrating a master meter used in royalty meter provings? | § 250.1202(e)
6. What are the requirements for calibrating mechanical-displacement provers and tank provers? | § 250.1202(f)
7. What correction factors must a lessee use when proving meters with a mechanical displacement prover, tank prover, or master meter? | § 250.1202(g)
8. What are the requirements for establishing and applying operating meter factors for liquid hydrocarbons? | § 250.1202(h)
9. Under what circumstances does a liquid hydrocarbon royalty meter need to be taken out of service, and what must a lessee do? | § 250.1202(i)
10. How must a lessee correct gross liquid hydrocarbon volumes to standard conditions? | § 250.1202(j)
11. What are the requirements for liquid hydrocarbon allocation meters? | § 250.1202(k)
12. What are the requirements for royalty and inventory tank facilities? | § 250.1202(l)
13. To which meters do MMS requirements for gas measurement apply? | § 250.1203(a)
14. What are the requirements for measuring gas? | § 250.1203(b)
15. What are the requirements for gas meter calibrations? | § 250.1203(c)
16. What must a lessee do if a gas meter is out of calibration or malfunctioning? | § 250.1203(d)
17. What are the requirements when natural gas from a Federal lease is transferred to a gas plant before royalty determination? | § 250.1203(e)
18. What are the requirements for measuring gas lost or used on a lease? | § 250.1203(f)
19. What are the requirements for the surface commingling of production? | § 250.1204(a)
20. What are the requirements for a periodic well test used for allocation? | § 250.1204(b)
21. What are the requirements for site security? | § 250.1205(a)
22. What are the requirements for using seals? | § 250.1205(b)
[63 FR 26370, May 12, 1998. Redesignated and amended at 63 FR 29479, 29487, May 29, 1998]
§ 250.1201
Definitions.
Terms not defined in this section have the meanings given in the applicable chapter of the API MPMS, which is incorporated by reference in 30 CFR 250.198. Terms used in Subpart L have the following meaning:
Allocation meter—a meter used to determine the portion of hydrocarbons attributable to one or more platforms, leases, units, or wells, in relation to the total production from a royalty or allocation measurement point.
API MPMS—the American Petroleum Institute's Manual of Petroleum Measurement Standards, chapters 1, 20, and 21.
British Thermal Unit (Btu)—the amount of heat needed to raise the temperature of one pound of water from 59.5 degrees Fahrenheit (59.5 °F) to 60.5 degrees Fahrenheit (60.5 °F) at standard pressure base (14.73 pounds per square inch absolute (psia)).
Compositional Analysis—separating mixtures into identifiable components expressed in mole percent.
Gas lost—gas that is neither sold nor used on the lease or unit nor used internally by the producer.
Gas processing plant—an installation that uses any process designed to remove elements or compounds (hydrocarbon and non-hydrocarbon) from gas, including absorption, adsorption, or refrigeration. Processing does not include treatment operations, including those necessary to put gas into marketable conditions such as natural pressure reduction, mechanical separation, heating, cooling, dehydration, desulphurization, and compression. The changing of pressures or temperatures in a reservoir is not processing.
Gas processing plant statement—a monthly statement showing the volume and quality of the inlet or field gas stream and the plant products recovered during the period, volume of plant fuel, flare and shrinkage, and the allocation of these volumes to the sources of the inlet stream.
Gas royalty meter malfunction—an error in any component of the gas measurement system which exceeds contractual tolerances.
Gas volume statement—a monthly statement showing gas measurement data, including the volume (Mcf) and quality (Btu) of natural gas which flowed through a meter.
Inventory tank—a tank in which liquid hydrocarbons are stored prior to royalty measurement. The measured volumes are used in the allocation process.
Liquid hydrocarbons (free liquids)—hydrocarbons which exist in liquid form at standard conditions after passing through separating facilities.
Malfunction factor—a liquid hydrocarbon royalty meter factor that differs from the previous meter factor by an amount greater than 0.0025.
Natural gas—a highly compressible, highly expandable mixture of hydrocarbons which occurs naturally in a gaseous form and passes a meter in vapor phase.
Operating meter—a royalty or allocation meter that is used for gas or liquid hydrocarbon measurement for any period during a calibration cycle.
Pressure base—the pressure at which gas volumes and quality are reported. The standard pressure base is 14.73 psia.
Prove—to determine (as in meter proving) the relationship between the volume passing through a meter at one set of conditions and the indicated volume at those same conditions.
Pipeline (retrograde) condensate—liquid hydrocarbons which drop out of the separated gas stream at any point in a pipeline during transmission to shore.
Royalty meter—a meter approved for the purpose of determining the volume of gas, oil, or other components removed, saved, or sold from a Federal lease.
Royalty tank—an approved tank in which liquid hydrocarbons are measured and upon which royalty volumes are based.
Run ticket—the invoice for liquid hydrocarbons measured at a royalty point.
Sales meter—a meter at which custody transfer takes place (not necessarily a royalty meter).
Seal—a device or approved method used to prevent tampering with royalty measurement components.
Standard conditions—atmospheric pressure of 14.73 pounds per square inch absolute (psia) and 60 °F.
Surface commingling—the surface mixing of production from two or more leases and/or unit participating areas prior to royalty measurement.
Temperature base—the temperature at which gas and liquid hydrocarbon volumes and quality are reported. The standard temperature base is 60 °F.
Verification/Calibration—testing and correcting, if necessary, a measuring device to ensure compliance with industry accepted, manufacturer's recommended, or regulatory required standard of accuracy.
You or your—the lessee or the operator or other lessees' representative engaged in operations in the Outer Continental Shelf (OCS).
[63 FR 26370, May 12, 1998. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 64 FR 72794, Dec. 28, 1999; 73 FR 20171, Apr. 15, 2008]
§ 250.1202
Liquid hydrocarbon measurement.
(a) What are the requirements for measuring liquid hydrocarbons? You must:
(1) Submit a written application to, and obtain approval from, the Regional Supervisor before commencing liquid hydrocarbon production, or making any changes to the previously-approved measurement and/or allocation procedures. Your application (which may also include any relevant gas measurement and surface commingling requests) must be accompanied by payment of the service fee listed in § 250.125. The service fees are divided into two levels based on complexity as shown in the following table.
Application type | Actions
(i) Simple applications | Applications to temporarily reroute production (for a duration not to exceed six months); Production tests prior to pipeline construction; Departures related to meter proving, well testing, or sampling frequency.
(ii) Complex applications | Creation of new facility measurement points (FMPs); Association of leases or units with existing FMPs; Inclusion of production from additional structures; Meter updates which add buy-back gas meters or pigging meters; Other applications which request deviations from the approved allocation procedures.
(2) Use measurement equipment that will accurately measure the liquid hydrocarbons produced from a lease or unit;
(3) Use procedures and correction factors according to the applicable chapters of the API MPMS as incorporated by reference in 30 CFR 250.198, when obtaining net standard volume and associated measurement parameters; and
(4) When requested by the Regional Supervisor, provide the pipeline (retrograde) condensate volumes as allocated to the individual leases or units.
(b) What are the requirements for liquid hydrocarbon royalty meters? You must:
(1) Ensure that the royalty meter facilities include the following approved components (or other MMS-approved components) which must be compatible with their connected systems:
(i) A meter equipped with a nonreset totalizer;
(ii) A calibrated mechanical displacement (pipe) prover, master meter, or tank prover;
(iii) A proportional-to-flow sampling device pulsed by the meter output;
(iv) A temperature measurement or temperature compensation device; and
(v) A sediment and water monitor with a probe located upstream of the divert valve.
(2) Ensure that the royalty meter facilities accomplish the following:
(i) Prevent flow reversal through the meter;
(ii) Protect meters subjected to pressure pulsations or surges;
(iii) Prevent the meter from being subjected to shock pressures greater than the maximum working pressure; and
(iv) Prevent meter bypassing.
(3) Maintain royalty meter facilities to ensure the following:
(i) Meters operate within the gravity range specified by the manufacturer;
(ii) Meters operate within the manufacturer's specifications for maximum and minimum flow rate for linear accuracy; and
(iii) Meters are reproven when changes in metering conditions affect the meters' performance such as changes in pressure, temperature, density (water content), viscosity, pressure, and flow rate.
(4) Ensure that sampling devices conform to the following:
(i) The sampling point is in the flowstream immediately upstream or downstream of the meter or divert valve (in accordance with the API MPMS as incorporated by reference in 30 CFR 250.198);
(ii) The sample container is vapor-tight and includes a power mixing device to allow complete mixing of the sample before removal from the container; and
(iii) The sample probe is in the center half of the pipe diameter in a vertical run and is located at least three pipe diameters downstream of any pipe fitting within a region of turbulent flow. The sample probe can be located in a horizontal pipe if adequate stream conditioning such as power mixers or static mixers are installed upstream of the probe according to the manufacturer's instructions.
(c) What are the requirements for run tickets? You must:
(1) For royalty meters, ensure that the run tickets clearly identify all observed data, all correction factors not included in the meter factor, and the net standard volume.
(2) For royalty tanks, ensure that the run tickets clearly identify all observed data, all applicable correction factors, on/off seal numbers, and the net standard volume.
(3) Pull a run ticket at the beginning of the month and immediately after establishing the monthly meter factor or a malfunction meter factor.
(4) Send all run tickets for royalty meters and tanks to the Regional Supervisor within 15 days after the end of the month;
(d) What are the requirements for liquid hydrocarbon royalty meter provings? You must:
(1) Permit MMS representatives to witness provings;
(2) Ensure that the integrity of the prover calibration is traceable to test measures certified by the National Institute of Standards and Technology;
(3) Prove each operating royalty meter to determine the meter factor monthly, but the time between meter factor determinations must not exceed 42 days;
(4) Obtain approval from the Regional Supervisor before proving on a schedule other than monthly; and
(5) Submit copies of all meter proving reports for royalty meters to the Regional Supervisor monthly within 15 days after the end of the month.
(e) What are the requirements for calibrating a master meter used in royalty meter provings? You must:
(1) Calibrate the master meter to obtain a master meter factor before using it to determine operating meter factors;
(2) Use a fluid of similar gravity, viscosity, temperature, and flow rate as the liquid hydrocarbons that flow through the operating meter to calibrate the master meter;
(3) Calibrate the master meter monthly, but the time between calibrations must not exceed 42 days;
(4) Calibrate the master meter by recording runs until the results of two consecutive runs (if a tank prover is used) or five out of six consecutive runs (if a mechanical-displacement prover is used) produce meter factor differences of no greater than 0.0002. Lessees must use the average of the two (or the five) runs that produced acceptable results to compute the master meter factor;
(5) Install the master meter upstream of any back-pressure or reverse flow check valves associated with the operating meter. However, the master meter may be installed either upstream or downstream of the operating meter; and
(6) Keep a copy of the master meter calibration report at your field location for 2 years.
(f) What are the requirements for calibrating mechanical-displacement provers and tank provers? You must:
(1) Calibrate mechanical-displacement provers and tank provers at least once every 5 years according to the API MPMS as incorporated by reference in 30 CFR 250.198; and
(2) Submit a copy of each calibration report to the Regional Supervisor within 15 days after the calibration.
(g) What correction factors must I use when proving meters with a mechanical-displacement prover, tank prover, or master meter? Calculate the following correction factors using the API MPMS as referenced in 30 CFR 250.198:
(1) The change in prover volume due to the effect of temperature on steel (Cts);
(2) The change in prover volume due to the effect of pressure on steel (Cps);
(3) The change in liquid volume due to the effect of temperature on a liquid (Ctl); and
(4) The change in liquid volume due to the effect of pressure on a liquid (Cpl).
(h) What are the requirements for establishing and applying operating meter factors for liquid hydrocarbons? (1) If you use a mechanical-displacement prover, you must record proof runs until five out of six consecutive runs produce a difference between individual runs of no greater than .05 percent. You must use the average of the five accepted runs to compute the meter factor.
(2) If you use a master meter, you must record proof runs until three consecutive runs produce a total meter factor difference of no greater than 0.0005. The flow rate through the meters during the proving must be within 10 percent of the rate at which the line meter will operate. The final meter factor is determined by averaging the meter factors of the three runs;
(3) If you use a tank prover, you must record proof runs until two consecutive runs produce a meter factor difference of no greater than .0005. The final meter factor is determined by averaging the meter factors of the two runs; and
(4) You must apply operating meter factors forward starting with the date of the proving.
(i) Under what circumstances does a liquid hydrocarbon royalty meter need to be taken out of service, and what must I do? (1) If the difference between the meter factor and the previous factor exceeds 0.0025 it is a malfunction factor, and you must:
(i) Remove the meter from service and inspect it for damage or wear;
(ii) Adjust or repair the meter, and reprove it;
(iii) Apply the average of the malfunction factor and the previous factor to the production measured through the meter between the date of the previous factor and the date of the malfunction factor; and
(iv) Indicate that a meter malfunction occurred and show all appropriate remarks regarding subsequent repairs or adjustments on the proving report.
(2) If a meter fails to register production, you must:
(i) Remove the meter from service, repair and reprove it;
(ii) Apply the previous meter factor to the production run between the date of that factor and the date of the failure; and
(iii) Estimate and report unregistered production on the run ticket.
(3) If the results of a royalty meter proving exceed the run tolerance criteria and all measures excluding the adjustment or repair of the meter cannot bring results within tolerance, you must:
(i) Establish a factor using proving results made before any adjustment or repair of the meter; and
(ii) Treat the established factor like a malfunction factor (see paragraph (i)(1) of this section).
(j) How must I correct gross liquid hydrocarbon volumes to standard conditions? To correct gross liquid hydrocarbon volumes to standard conditions, you must:
(1) Include Cpl factors in the meter factor calculation or list and apply them on the appropriate run ticket.
(2) List Ctl factors on the appropriate run ticket when the meter is not automatically temperature compensated.
(k) What are the requirements for liquid hydrocarbon allocation meters? For liquid hydrocarbon allocation meters you must:
(1) Take samples continuously proportional to flow or daily (use the procedure in the applicable chapter of the API MPMS as incorporated by reference in 30 CFR 250.198;
(2) For turbine meters, take the sample proportional to the flow only;
(3) Prove operating allocation meters monthly if they measure 50 or more barrels per day per meter; or
(4) Prove operating allocation meters quarterly if they measure less than 50 barrels per day per meter;
(5) Keep a copy of the proving reports at the field location for 2 years;
(6) Adjust and reprove the meter if the meter factor differs from the previous meter factor by more than 2 percent and less than 7 percent;
(7) For turbine meters, remove from service, inspect and reprove the meter if the factor differs from the previous meter factor by more than 2 percent and less than 7 percent;
(8) Repair and reprove, or replace and prove the meter if the meter factor differs from the previous meter factor by 7 percent or more; and
(9) Permit MMS representatives to witness provings.
(l) What are the requirements for royalty and inventory tank facilities? You must:
(1) Equip each royalty and inventory tank with a vapor-tight thief hatch, a vent-line valve, and a fill line designed to minimize free fall and splashing;
(2) For royalty tanks, submit a complete set of calibration charts (tank tables) to the Regional Supervisor before using the tanks for royalty measurement;
(3) For inventory tanks, retain the calibration charts for as long as the tanks are in use and submit them to the Regional Supervisor upon request; and
(4) Obtain the volume and other measurement parameters by using correction factors and procedures in the API MPMS as incorporated by reference in 30 CFR 250.198.
[63 FR 26370, May 12, 1998. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 63 FR 33853, June 22, 1998; 64 FR 72794, Dec. 28 1999; 71 FR 40912, July 19, 2006; 72 FR 25201, May 4, 2007; 73 FR 20171, Apr. 15, 2008]
§ 250.1203
Gas measurement.
(a) To which meters do MMS requirements for gas measurement apply? MMS requirements for gas measurements apply to all OCS gas royalty and allocation meters.
(b) What are the requirements for measuring gas? You must:
(1) Submit a written application to, and obtain approval from, the Regional Supervisor before commencing gas production, or making any changes to the previously-approved measurement and/or allocation procedures. Your application (which may also include any relevant liquid hydrocarbon measurement and surface commingling requests) must be accompanied by payment of the service fee listed in § 250.125. The service fees are divided into two levels based on complexity, see table in § 250.1202(a)(1).
(2) Design, install, use, maintain, and test measurement equipment to ensure accurate and verifiable measurement. You must follow the recommendations in API MPMS as incorporated by reference in 30 CFR 250.198.
(3) Ensure that the measurement components demonstrate consistent levels of accuracy throughout the system.
(4) Equip the meter with a chart or electronic data recorder. If an electronic data recorder is used, you must follow the recommendations in API MPMS as referenced in 30 CFR 250.198.
(5) Take proportional-to-flow or spot samples upstream or downstream of the meter at least once every 6 months.
(6) When requested by the Regional Supervisor, provide available information on the gas quality.
(7) Ensure that standard conditions for reporting gross heating value (Btu) are at a base temperature of 60 °F and at a base pressure of 14.73 psia and reflect the same degree of water saturation as in the gas volume.
(8) When requested by the Regional Supervisor, submit copies of gas volume statements for each requested gas meter. Show whether gas volumes and gross Btu heating values are reported at saturated or unsaturated conditions; and
(9) When requested by the Regional Supervisor, provide volume and quality statements on dispositions other than those on the gas volume statement.
(c) What are the requirements for gas meter calibrations? You must:
(1) Calibrate meters monthly, but do not exceed 42 days between calibrations;
(2) Calibrate each meter by using the manufacturer's specifications;
(3) Conduct calibrations as close as possible to the average hourly rate of flow since the last calibration;
(4) Retain calibration reports at the field location for 2 years, and send the reports to the Regional Supervisor upon request; and
(5) Permit MMS representatives to witness calibrations.
(d) What must I do if a gas meter is out of calibration or malfunctioning? If a gas meter is out of calibration or malfunctioning, you must:
(1) If the readings are greater than the contractual tolerances, adjust the meter to function properly or remove it from service and replace it.
(2) Correct the volumes to the last acceptable calibration as follows:
(i) If the duration of the error can be determined, calculate the volume adjustment for that period.
(ii) If the duration of the error cannot be determined, apply the volume adjustment to one-half of the time elapsed since the last calibration or 21 days, whichever is less.
(e) What are the requirements when natural gas from a Federal lease on the OCS is transferred to a gas plant before royalty determination? If natural gas from a Federal lease on the OCS is transferred to a gas plant before royalty determination:
(1) You must provide the following to the Regional Supervisor upon request:
(i) A copy of the monthly gas processing plant allocation statement; and
(ii) Gross heating values of the inlet and residue streams when not reported on the gas plant statement.
(2) You must permit MMS to inspect the measurement and sampling equipment of natural gas processing plants that process Federal production.
(f) What are the requirements for measuring gas lost or used on a lease? (1) You must either measure or estimate the volume of gas lost or used on a lease.
(2) If you measure the volume, document the measurement equipment used and include the volume measured.
(3) If you estimate the volume, document the estimating method, the data used, and the volumes estimated.
(4) You must keep the documentation, including the volume data, easily obtainable for inspection at the field location for at least 2 years, and must retain the documentation at a location of your choosing for at least 7 years after the documentation is generated, subject to all other document retention and production requirements in 30 U.S.C. 1713 and 30 CFR part 212.
(5) Upon the request of the Regional Supervisor, you must provide copies of the records.
[63 FR 26370, May 12, 1998. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 63 FR 33853, June 22, 1998; 64 FR 72794, Dec. 28, 1999; 71 FR 40912, July 19, 2006]
§ 250.1204
Surface commingling.
(a) What are the requirements for the surface commingling of production? You must:
(1) Submit a written application to, and obtain approval from, the Regional Supervisor before commencing the commingling of production or making any changes to the previously approved commingling procedures. Your application (which may also include any relevant liquid hydrocarbon and gas measurement requests) must be accompanied by payment of the service fee listed in § 250.125. The service fees are divided into two levels based on complexity, see table in § 250.1202(a)(1).
(2) Upon the request of the Regional Supervisor, lessees who deliver State lease production into a Federal commingling system must provide volumetric or fractional analysis data on the State lease production through the designated system operator.
(b) What are the requirements for a periodic well test used for allocation? You must:
(1) Conduct a well test at least once every 2 months (1 time every 60 days) unless the Regional Supervisor approves a different frequency;
(2) Follow the well test procedures in 30 CFR part 250, Subpart K; and
(3) Retain the well test data at the field location for 2 years.
[63 FR 26370, May 12, 1998. Redesignated at 63 FR 29479, May 29, 1998; 63 FR 33853, June 22, 1998; 71 FR 40913, July 19, 2006; 73 FR 20171, Apr. 15, 2008]
§ 250.1205
Site security.
(a) What are the requirements for site security? You must:
(1) Protect Federal production against production loss or theft;
(2) Post a sign at each royalty or inventory tank which is used in the royalty determination process. The sign must contain the name of the facility operator, the size of the tank, and the tank number;
(3) Not bypass MMS-approved liquid hydrocarbon royalty meters and tanks; and
(4) Report the following to the Regional Supervisor as soon as possible, but no later than the next business day after discovery:
(i) Theft or mishandling of production;
(ii) Tampering or bypassing any component of the royalty measurement facility; and
(iii) Falsifying production measurements.
(b) What are the requirements for using seals? You must:
(1) Seal the following components of liquid hydrocarbon royalty meter installations to ensure that tampering cannot occur without destroying the seal:
(i) Meter component connections from the base of the meter up to and including the register;
(ii) Sampling systems including packing device, fittings, sight glass, and container lid;
(iii) Temperature and gravity compensation device components;
(iv) All valves on lines leaving a royalty or inventory storage tank, including load-out line valves, drain-line valves, and connection-line valves between royalty and non-royalty tanks; and
(v) Any additional components required by the Regional Supervisor.
(2) Seal all bypass valves of gas royalty and allocation meters.
(3) Number and track the seals and keep the records at the field location for at least 2 years; and
(4) Make the records of seals available for MMS inspection.

Subpart M—Unitization

Source:
62 FR 5331, Feb. 5, 1997, unless otherwise noted. Redesignated at 63 FR 29479, May 29, 1998.
§ 250.1300
What is the purpose of this subpart?
This subpart explains how Outer Continental Shelf (OCS) leases are unitized. If you are an OCS lessee, use the regulations in this subpart for both competitive reservoir and unitization situations. The purpose of joint development and unitization is to:
(a) Conserve natural resources;
(b) Prevent waste; and/or
(c) Protect correlative rights, including Federal royalty interests.
§ 250.1301
What are the requirements for unitization?
(a) Voluntary unitization. You and other OCS lessees may ask the Regional Supervisor to approve a request for voluntary unitization. The Regional Supervisor may approve the request for voluntary unitization if unitized operations:
(1) Promote and expedite exploration and development; or
(2) Prevent waste, conserve natural resources, or protect correlative rights, including Federal royalty interests, of a reasonably delineated and productive reservoir.
(b) Compulsory unitization. The Regional Supervisor may require you and other lessees to unitize operations of a reasonably delineated and productive reservoir if unitized operations are necessary to:
(1) Prevent waste;
(2) Conserve natural resources; or
(3) Protect correlative rights, including Federal royalty interests.
(c) Unit area. The area that a unit includes is the minimum number of leases that will allow the lessees to minimize the number of platforms, facility installations, and wells necessary for efficient exploration, development, and production of mineral deposits, oil and gas reservoirs, or potential hydrocarbon accumulations common to two or more leases. A unit may include whole leases or portions of leases.
(d) Unit agreement. You, the other lessees, and the unit operator must enter into a unit agreement. The unit agreement must: allocate benefits to unitized leases, designate a unit operator, and specify the effective date of the unit agreement. The unit agreement must terminate when: the unit no longer produces unitized substances, and the unit operator no longer conducts drilling or well-workover operations (§ 250.180) under the unit agreement, unless the Regional Supervisor orders or approves a suspension of production under § 250.170.
(e) Unit operating agreement. The unit operator and the owners of working interests in the unitized leases must enter into a unit operating agreement. The unit operating agreement must describe how all the unit participants will apportion all costs and liabilities incurred maintaining or conducting operations. When a unit involves one or more net-profit-share leases, the unit operating agreement must describe how to attribute costs and credits to the net-profit-share lease(s), and this part of the agreement must be approved by the Regional Supervisor. Otherwise, you must provide a copy of the unit operating agreement to the Regional Supervisor, but the Regional Supervisor does not need to approve the unit operating agreement.
(f) Extension of a lease covered by unit operations. If your unit agreement expires or terminates, or the unit area adjusts so that no part of your lease remains within the unit boundaries, your lease expires unless:
(1) Its initial term has not expired;
(2) You conduct drilling, production, or well-reworking operations on your lease consistent with applicable regulations; or
(3) MMS orders or approves a suspension of production or operations for your lease.
(g) Unit operations. If your lease, or any part of your lease, is subject to a unit agreement, the entire lease continues for the term provided in the lease, and as long thereafter as any portion of your lease remains part of the unit area, and as long as operations continue the unit in effect.
(1) If you drill, produce or perform well-workover operations on a lease within a unit, each lease, or part of a lease, in the unit will remain active in accordance with the unit agreement. Following a discovery, if your unit ceases drilling activities for a reasonable time period between the delineation of one or more reservoirs and the initiation of actual development drilling or production operations and that time period would extend beyond your lease's primary term or any extension under § 250.180, the unit operator must request and obtain MMS approval of a suspension of production under § 250.170 in order to keep the unit from terminating.
(2) When a lease in a unit agreement is beyond the primary term and the lease or unit is not producing, the lease will expire unless:
(i) You conduct a continuous drilling or well reworking program designed to develop or restore the lease or unit production; or
(ii) MMS orders or approves a suspension of operations under § 250.170.
[62 FR 5331, Feb. 5, 1997. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 64 FR 72794, Dec. 28, 1999; 73 FR 20172, Apr. 15, 2008]
§ 250.1302
What if I have a competitive reservoir on a lease?
(a) The Regional Supervisor may require you to conduct development and production operations in a competitive reservoir under either a joint Development and Production Plan or a unitization agreement. A competitive reservoir has one or more producing or producible well completions on each of two or more leases, or portions of leases, with different lease operating interests. For purposes of this paragraph, a producible well completion is a well which is capable of production and which is shut in at the well head or at the surface but not necessarily connected to production facilities and from which the operator plans future production.
(b) You may request that the Regional Supervisor make a preliminary determination whether a reservoir is competitive. When you receive the preliminary determination, you have 30 days (or longer if the Regional Supervisor allows additional time) to concur or to submit an objection with supporting evidence if you do not concur. The Regional Supervisor will make a final determination and notify you and the other lessees.
(c) If you conduct drilling or production operations in a reservoir determined competitive by the Regional Supervisor, you and the other affected lessees must submit for approval a joint plan of operations. You must submit the joint plan within 90 days after the Regional Supervisor makes a final determination that the reservoir is competitive. The joint plan must provide for the development and/or production of the reservoir. You may submit supplemental plans for the Regional Supervisor's approval.
(d) If you and the other affected lessees cannot reach an agreement on a joint Development and Production Plan within the approved period of time, each lessee must submit a separate plan to the Regional Supervisor. The Regional Supervisor will hold a hearing to resolve differences in the separate plans. If the differences in the separate plans are not resolved at the hearing and the Regional Supervisor determines that unitization is necessary under § 250.1301(b), MMS will initiate unitization under § 250.1304.
[62 FR 5331, Feb. 5, 1997. Redesignated and amended at 63 FR 29479, 29486, May 29, 1998]
§ 250.1303
How do I apply for voluntary unitization?
(a) You must file a request for a voluntary unit with the Regional Supervisor. Your request must include:
(1) A draft of the proposed unit agreement;
(2) A proposed initial plan of operation;
(3) Supporting geological, geophysical, and engineering data; and
(4) Other information that may be necessary to show that the unitization proposal meets the criteria of § 250.1300.
(b) The unit agreement must comply with the requirements of this part. MMS will maintain and provide a model unit agreement for you to follow. If MMS revises the model, MMS will publish the revised model in the Federal Register. If you vary your unit agreement from the model agreement, you must obtain the approval of the Regional Supervisor.
(c) After the Regional Supervisor accepts your unitization proposal, you, the other lessees, and the unit operator must sign and file copies of the unit agreement, the unit operating agreement, and the initial plan of operation with the Regional Supervisor for approval.
(d) You must pay the service fee listed in § 250.125 of this part with your request for a voluntary unitization proposal or the expansion of a previously approved voluntary unit to include additional acreage. Additionally, you must pay the service fee listed in § 250.125 with your request for unitization revision.
[62 FR 5331, Feb. 5, 1997. Redesignated and amended at 63 FR 29479, 29487, May 29, 1998; 70 FR 49876, Aug. 25, 2005]
§ 250.1304
How will MMS require unitization?
(a) If the Regional Supervisor determines that unitization of operations within a proposed unit area is necessary to prevent waste, conserve natural resources of the OCS, or protect correlative rights, including Federal royalty interests, the Regional Supervisor may require unitization.
(b) If you ask MMS to require unitization, you must file a request with the Regional Supervisor. You must include a proposed unit agreement as described in §§ 250.1301(d) and 250.1303(b); a proposed unit operating agreement; a proposed initial plan of operation; supporting geological, geophysical, and engineering data; and any other information that may be necessary to show that unitization meets the criteria of § 250.1300. The proposed unit agreement must include a counterpart executed by each lessee seeking compulsory unitization. Lessees who seek compulsory unitization must simultaneously serve on the nonconsenting lessees copies of:
(1) The request;
(2) The proposed unit agreement with executed counterparts;
(3) The proposed unit operating agreement; and
(4) The proposed initial plan of operation.
(c) If the Regional Supervisor initiates compulsory unitization, MMS will serve all lessees of the proposed unit area with a proposed unitization plan and a statement of reasons for the proposed unitization.
(d) The Regional Supervisor will not require unitization until MMS provides all lessees of the proposed unit area written notice and an opportunity for a hearing. If you want MMS to hold a hearing, you must request it within 30 days after you receive written notice from the Regional Supervisor or after you are served with a request for compulsory unitization from another lessee.
(e) MMS will not hold a hearing under this paragraph until at least 30 days after MMS provides written notice of the hearing date to all parties owning interests that would be made subject to the unit agreement. The Regional Supervisor must give all lessees of the proposed unit area an opportunity to submit views orally and in writing and to question both those seeking and those opposing compulsory unitization. Adjudicatory procedures are not required. The Regional Supervisor will make a decision based upon a record of the hearing, including any written information made a part of the record. The Regional Supervisor will arrange for a court reporter to make a verbatim transcript. The party seeking compulsory unitization must pay for the court reporter and pay for and provide to the Regional Supervisor within 10 days after the hearing three copies of the verbatim transcript.
(f) The Regional Supervisor will issue an order that requires or rejects compulsory unitization. That order must include a statement of reasons for the action taken and identify those parts of the record which form the basis of the decision. Any adversely affected party may appeal the final order of the Regional Supervisor under 30 CFR part 290.
[62 FR 5331, Feb. 5, 1997. Redesignated and amended at 63 FR 29479, 29487, May 29, 1998]

Subpart N—Outer Continental Shelf (OCS) Civil Penalties

Source:
62 FR 42668, Aug. 8, 1997, unless otherwise noted. Redesignated at 63 FR 29479, May 29, 1998.
§ 250.1400
How does MMS begin the civil penalty process?
This subpart explains MMS's civil penalty procedures whenever a lessee, operator or other person engaged in oil, gas, sulphur or other minerals operations in the OCS has a violation. Whenever MMS determines, on the basis of available evidence, that a violation occurred and a civil penalty review is appropriate, it will prepare a case file. MMS will appoint a Reviewing Officer.
§ 250.1401
Index table.
The following table is an index of the sections in this subpart:
§ 250.1401Table
Definitions | § 250.1402
What is the maximum civil penalty? | § 250.1403
Which violations will MMS review for potential civil penalties? | § 250.1404
When is a case file developed? | § 250.1405
When will MMS notify me and provide penalty information? | § 250.1406
How do I respond to the letter of notification? | § 250.1407
When will I be notified of the Reviewing Officer's decision? | § 250.1408
What are my appeal rights? | § 250.1409
[62 FR 42668, Aug. 8, 1997. Redesignated and amended at 63 FR 29479, 29487, May 29, 1998]
§ 250.1402
Definitions.
Terms used in this subpart have the following meaning:
Case file means an MMS document file containing information and the record of evidence related to the alleged violation.
Civil penalty means a fine. It is an MMS regulatory enforcement tool used in addition to Notices of Incidents of Noncompliance and directed suspensions of production or other operations.
Reviewing Officer means an MMS employee assigned to review case files and assess civil penalties.
Violation means failure to comply with the Outer Continental Shelf Lands Act (OCSLA) or any other applicable laws, with any regulations issued under the OCSLA, or with the terms or provisions of leases, licenses, permits, rights-of-way, or other approvals issued under the OCSLA.
Violator means a person responsible for a violation.
[62 FR 42668, Aug. 8, 1997. Redesignated at 63 FR 29479, May 29, 1998, as amended at 71 FR 23864, Apr. 25, 2006]
§ 250.1403
What is the maximum civil penalty?
The maximum civil penalty is $35,000 per day per violation.
[72 FR 8899, Feb. 28, 2007]
§ 250.1404
Which violations will MMS review for potential civil penalties?
MMS will review each of the following violations for potential civil penalties:
(a) Violations that you do not correct within the period MMS grants;
(b) Violations that MMS determines may constitute, or constituted, a threat of serious, irreparable, or immediate harm or damage to life (including fish and other aquatic life), property, any mineral deposit, or the marine, coastal, or human environment; or
(c) Violations that cause serious, irreparable, or immediate harm or damage to life (including fish and other aquatic life), property, any mineral deposit, or the marine, coastal, or human environment.
(d) Violations of the oil spill financial responsibility requirements at 30 CFR part 253.
[62 FR 5331, Feb. 5, 1997. Redesignated and amended at 63 FR 29479, 29487, May 29, 1998; 63 FR 42711, Aug. 11, 1998; 64 FR 9066, Feb. 24, 1999]
§ 250.1405
When is a case file developed?
MMS will develop a case file during its investigation of the violation, and forward it to a Reviewing Officer if any of the conditions in § 250.1404 exist. The Reviewing Officer will review the case file and determine if a civil penalty is appropriate. The Reviewing Officer may administer oaths and issue subpoenas requiring witnesses to attend meetings, submit depositions, or produce evidence.
[62 FR 42668, Aug. 8, 1997. Redesignated and amended at 63 FR 29479, 29487, May 29, 1998]
§ 250.1406
When will MMS notify me and provide penalty information?
If the Reviewing Officer determines that a civil penalty should be assessed, the Reviewing Officer will send the violator a letter of notification. The letter of notification will include:
(a) The amount of the proposed civil penalty;
(b) Information on the violation(s); and
(c) Instruction on how to obtain a copy of the case file, schedule a meeting, submit information, or pay the penalty.
[62 FR 42668, Aug. 8, 1997. Redesignated at 63 FR 29479, May 29, 1998; 64 FR 9066, Feb. 24, 1999]
§ 250.1407
How do I respond to the letter of notification?
You have 30 calendar days after you receive the Reviewing Officer's letter to either:
(a) Request, in writing, a meeting with the Reviewing Officer;
(b) Submit additional information; or
(c) Pay the proposed civil penalty.
§ 250.1408
When will I be notified of the Reviewing Officer's decision?
At the end of the 30 calendar days or after the meeting and submittal of additional information, the Reviewing Officer will review the case file, including all information you submitted, and send you a decision. The decision will include the amount of any final civil penalty, the basis for the civil penalty, and instructions for paying or appealing the civil penalty.
§ 250.1409
What are my appeal rights?
(a) When you receive the Reviewing Officer's final decision, you have 60 days to either pay the penalty or file an appeal in accordance with 30 CFR part 290, subpart A.
(b) If you file an appeal, you must either:
(1) Submit a surety bond in the amount of the penalty to the Regional Adjudication Office in the Region where the penalty was assessed, following instructions that the Reviewing Officer will include in the final decision; or
(2) Notify the Regional Adjudication Office, in the Region where the penalty was assessed, that you want your lease-specific/area-wide bond on file to be used as the bond for the penalty amount.
(c) If you choose the alternative in paragraph (b)(2) of this section, the Regional Director may require additional security (i.e., security in excess of your existing bond) to ensure sufficient coverage during an appeal. In that event, the Regional Director will require you to post the supplemental bond with the regional office in the same manner as under §§ 256.53(d) through (f) of this chapter. If the Regional Director determines the appeal should be covered by a lease-specific abandonment account then you must establish an account that meets the requirements of § 256.56.
(d) If you do not either pay the penalty or file a timely appeal, MMS will take one or more of the following actions:
(1) We will collect the amount you were assessed, plus interest, late payment charges, and other fees as provided by law, from the date you received the Reviewing Officer's final decision until the date we receive payment;
(2) We may initiate additional enforcement, including, if appropriate, cancellation of the lease, right-of-way, license, permit, or approval, or the forfeiture of a bond under this part; or
(3) We may bar you from doing further business with the Federal Government according to Executive Orders 12549 and 12689, and section 2455 of the Federal Acquisition Streamlining Act of 1994, 31 U.S.C. 6101. The Department of the Interior's regulations implementing these authorities are found at 43 CFR part 12, subpart D.
[64 FR 26257, May 13, 1999, as amended at 65 FR 2875, Jan. 19, 2000]

Subpart O—Well Control and Production Safety Training

Source:
65 FR 49490, Aug. 14, 2000, unless otherwise noted.
§ 250.1500
Definitions.
Terms used in this subpart have the following meaning:
Employee means direct employees of the lessees who are assigned well control or production safety duties.
I or you means the lessee engaged in oil, gas, or sulphur operations in the Outer Continental Shelf (OCS).
Lessee means a person who has entered into a lease with the United States to explore for, develop, and produce the leased minerals. The term lessee also includes an owner of operating rights for that lease and the MMS-approved assignee of that lease.
Production safety means production operations as well as the installation, repair, testing, maintenance, or operation of surface or subsurface safety devices.
Well control means drilling, well completion, well workover, and well servicing operations. For purposes of this subpart, well completion/well workover means those operations following the drilling of a well that are intended to establish or restore production to a well. It includes small tubing operations but does not include well servicing. Well servicing means snubbing, coil tubing, and wireline operations.
§ 250.1501
What is the goal of my training program?
The goal of your training program must be safe and clean OCS operations. To accomplish this, you must ensure that your employees and contract personnel engaged in well control or production safety operations understand and can properly perform their duties.
§ 250.1503
What are my general responsibilities for training?
(a) You must establish and implement a training program so that all of your employees are trained to competently perform their assigned well control and production safety duties. You must verify that your employees understand and can perform the assigned well control or production safety duties.
(b) You must have a training plan that specifies the type, method(s), length, frequency, and content of the training for your employees. Your training plan must specify the method(s) of verifying employee understanding and performance. This plan must include at least the following information:
(1) Procedures for training employees in well control or production safety practices;
(2) Procedures for evaluating the training programs of your contractors;
(3) Procedures for verifying that all employees and contractor personnel engaged in well control or production safety operations can perform their assigned duties;
(4) Procedures for assessing the training needs of your employees on a periodic basis;
(5) Recordkeeping and documentation procedures; and
(6) Internal audit procedures.
(c) Upon request of the District Manager or Regional Supervisor, you must provide:
(1) Copies of training documentation for personnel involved in well control or production safety operations during the past 5 years; and
(2) A copy of your training plan.
§ 250.1504
May I use alternative training methods?
You may use alternative training methods. These methods may include computer-based learning, films, or their equivalents. This training should be reinforced by appropriate demonstrations and “hands-on” training. Alternative training methods must be conducted according to, and meet the objectives of, your training plan.
§ 250.1505
Where may I get training for my employees?
You may get training from any source that meets the requirements of your training plan.
§ 250.1506
How often must I train my employees?
You determine the frequency of the training you provide your employees. You must do all of the following:
(a) Provide periodic training to ensure that employees maintain understanding of, and competency in, well control or production safety practices;
(b) Establish procedures to verify adequate retention of the knowledge and skills that employees need to perform their assigned well control or production safety duties; and
(c) Ensure that your contractors' training programs provide for periodic training and verification of well control or production safety knowledge and skills.
§ 250.1507
How will MMS measure training results?
MMS may periodically assess your training program, using one or more of the methods in this section.
(a) Training system audit. MMS or its authorized representative may conduct a training system audit at your office. The training system audit will compare your training program against this subpart. You must be prepared to explain your overall training program and produce evidence to support your explanation.
(b) Employee or contract personnel interviews. MMS or its authorized representative may conduct interviews at either onshore or offshore locations to inquire about the types of training that were provided, when and where this training was conducted, and how effective the training was.
(c) Employee or contract personnel testing. MMS or its authorized representative may conduct testing at either onshore or offshore locations for the purpose of evaluating an individual's knowledge and skills in perfecting well control and production safety duties.
(d) Hands-on production safety, simulator, or live well testing. MMS or its authorized representative may conduct tests at either onshore or offshore locations. Tests will be designed to evaluate the competency of your employees or contract personnel in performing their assigned well control and production safety duties. You are responsible for the costs associated with this testing, excluding salary and travel costs for MMS personnel.
§ 250.1508
What must I do when MMS administers written or oral tests?
MMS or its authorized representative may test your employees or contract personnel at your worksite or at an onshore location. You and your contractors must:
(a) Allow MMS or its authorized representative to administer written or oral tests; and
(b) Identify personnel by current position, years of experience in present position, years of total oil field experience, and employer's name (e.g., operator, contractor, or sub-contractor company name).
§ 250.1509
What must I do when MMS administers or requires hands-on, simulator, or other types of testing?
If MMS or its authorized representative conducts, or requires you or your contractor to conduct hands-on, simulator, or other types of testing, you must:
(a) Allow MMS or its authorized representative to administer or witness the testing;
(b) Identify personnel by current position, years of experience in present position, years of total oil field experience, and employer's name (e.g., operator, contractor, or sub-contractor company name); and
(c) Pay for all costs associated with the testing, excluding salary and travel costs for MMS personnel.
§ 250.1510
What will MMS do if my training program does not comply with this subpart?
If MMS determines that your training program is not in compliance, we may initiate one or more of the following enforcement actions:
(a) Issue an Incident of Noncompliance (INC);
(b) Require you to revise and submit to MMS your training plan to address identified deficiencies;
(c) Assess civil/criminal penalties; or
(d) Initiate disqualification procedures.

Subpart P—Sulphur Operations

Source:
56 FR 32100, July 15, 1991, unless otherwise noted. Redesignated at 63 FR 29479, May 29, 1998.
§ 250.1600
Performance standard.
Operations to discover, develop, and produce sulphur in the OCS shall be in accordance with an approved Exploration Plan or Development and Production Plan and shall be conducted in a manner to protect against harm or damage to life (including fish and other aquatic life), property, natural resources of the OCS including any mineral deposits (in areas leased or not leased), the national security or defense, and the marine, coastal, or human environment.
§ 250.1601
Definitions.
Terms used in this subpart shall have the meanings as defined below:
Air line means a tubing string that is used to inject air within a sulphur producing well to airlift sulphur out of the well.
Bleedwater means a mixture of mine water or booster water and connate water that is produced by a bleedwell.
Bleedwell means a well drilled into a producing sulphur deposit that is used to control the mine pressure generated by the injection of mine water.
Brine means the water containing dissolved salt obtained from a brine well by circulating water into and out of a cavity in the salt core of a salt dome.
Brine well means a well drilled through cap rock into the core at a salt dome for the purpose of producing brine.
Cap rock means the rock formation, a body of limestone, anhydride, and/or gypsum, overlying a salt dome.
Sulphur deposit means a formation of rock that contains elemental sulphur.
Sulphur production rate means the number of long tons of sulphur produced during a certain period of time, usually per day.
§ 250.1602
Applicability.
(a) The requirements of this subpart P are applicable to all exploration, development, and production operations under an OCS sulphur lease. Sulphur operations include all activities conducted under a lease for the purpose of discovery or delineation of a sulphur deposit and for the development and production of elemental sulphur. Sulphur operations also include activities conducted for related purposes. Activities conducted for related purposes include, but are not limited to, production of other minerals, such as salt, for use in the exploration for or the development and production of sulphur. The lessee must have obtained the right to produce and/or use these other minerals.
(b) Lessees conducting sulphur operations in the OCS shall comply with the requirements of the applicable provisions of subparts A, B, C, I, J, M, N, O, and Q of this part.
(c) Lessees conducting sulphur operations in the OCS are also required to comply with the requirements in the applicable provisions of subparts D, E, F, H, K, and L of this part where such provisions specifically are referenced in this subpart.
[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998, as amended at 72 FR 25201, May 4, 2007]
§ 250.1603
Determination of sulphur deposit.
(a) Upon receipt of a written request from the lessee, the District Manager will determine whether a sulphur deposit has been defined that contains sulphur in paying quantities (i.e., sulphur in quantities sufficient to yield a return in excess of the costs, after completion of the wells, of producing minerals at the wellheads).
(b) A determination under paragraph (a) of this section shall be based upon the following:
(1) Core analyses that indicate the presence of a producible sulphur deposit (including an assay of elemental sulphur);
(2) An estimate of the amount of recoverable sulphur in long tons over a specified period of time; and
(3) Contour map of the cap rock together with isopach map showing the extent and estimated thickness of the sulphur deposit.
§ 250.1604
General requirements.
Sulphur lessees shall comply with requirements of this section when conducting well-drilling, well-completion, well-workover, or production operations.
(a) Equipment movement. The movement of well-drilling, well-completion, or well-workover rigs and related equipment on and off an offshore platform, or from one well to another well on the same offshore platform, including rigging up and rigging down, shall be conducted in a safe manner.
(b) Hydrogen sulfide (H 2 S). When a drilling, well-completion, well-workover, or production operation is being conducted on a well in zones known to contain H2S or in zones where the presence of H2S is unknown (as defined in 30 CFR 250.490 of this part), the lessee shall take appropriate precautions to protect life and property, especially during operations such as dismantling wellhead equipment and flow lines and circulating the well. The lessee shall also take appropriate precautions when H2S is generated as a result of sulphur production operations. The lessee shall comply with the requirements in § 250.490 of this part as well as the requirements of this subpart.
(c) Welding and burning practices and procedures. All welding, burning, and hot-tapping activities involved in drilling, well-completion, well-workover or production operations shall be conducted with properly maintained equipment, trained personnel, and appropriate procedures in order to minimize the danger to life and property according to the specific requirements in § 250.109 through § 250.113 of this part.
(d) Electrical requirements. All electrical equipment and systems involved in drilling, well-completion, well-workover, and production operations shall be designed, installed, equipped, protected, operated, and maintained so as to minimize the danger to life and property in accordance with the requirements of § 250.114 of this part.
(e) Structures on fixed OCS platforms. Derricks, cranes, masts, substructures, and related equipment shall be selected, designed, installed, used, and maintained so as to be adequate for the potential loads and conditions of loading that may be encountered during the operations. Prior to moving equipment such as a well-drilling, well-completion, or well-workover rig or associated equipment or production equipment onto a platform, the lessee shall determine the structural capability of the platform to safely support the equipment and operations, taking into consideration corrosion protection, platform age, and previous stresses.
(f) Traveling-block safety device. After August 14, 1992, all drilling units being used for drilling, well-completion, or well-workover operations that have both a traveling block and a crown block shall be equipped with a safety device that is designed to prevent the traveling block from striking the crown block. The device shall be checked for proper operation weekly and after each drill-line slipping operation. The results of the operational check shall be entered in the operations log.
[56 FR 32100, July 15, 1991. Redesignated and amended at 63 FR 29479, 29487, May 29, 1998; 67 FR 51760, Aug. 9, 2002; 68 FR 8435, Feb. 20, 2003]
§ 250.1605
Drilling requirements.
(a) Lessees of OCS sulphur leases shall conduct drilling operations in accordance with §§ 250.1605 through 250.1619 of this subpart and with other requirements of this part, as appropriate.
(b) Fitness of drilling unit. (1) Drilling units shall be capable of withstanding the oceanographic and meteorological conditions for the proposed season and location of operations.
(2) Prior to commencing operation, drilling units shall be made available for a complete inspection by the District Manager.
(3) The lessee shall provide information and data on the fitness of the drilling unit to perform the proposed drilling operation. The information shall be submitted with, or prior to, the submission of Form MMS-123, Application for Permit to Drill (APD), in accordance with § 250.1617 of this subpart. After a drilling unit has been approved by an MMS district office, the information required in this paragraph need not be resubmitted unless required by the District Manager or there are changes in the equipment that affect the rated capacity of the unit.
(c) Oceanographic, meteorological, and drilling unit performance data. Where oceanographic, meteorological, and drilling unit performance data are not otherwise readily available, lessees shall collect and report such data upon request to the District Manager. The type of information to be collected and reported will be determined by the District Manager in the interests of safety in the conduct of operations and the structural integrity of the drilling unit.
(d) Foundation requirements. When the lessee fails to provide sufficient information pursuant to §§ 250.211 through 250.228 and 250.241 through 250.262 of this part to support a determination that the seafloor is capable of supporting a specific bottom-founded drilling unit under the site-specific soil and oceanographic conditions, the District Manager may require that additional surveys and soil borings be performed and the results submitted for review and evaluation by the District Manager before approval is granted for commencing drilling operations.
(e) Tests, surveys, and samples. (1) Lessees shall drill and take cores and/or run well and mud logs through the objective interval to determine the presence, quality, and quantity of sulphur and other minerals (e.g., oil and gas) in the cap rock and the outline of the commercial sulphur deposit.
(2) Inclinational surveys shall be obtained on all vertical wells at intervals not exceeding 1,000 feet during the normal course of drilling. Directional surveys giving both inclination and azimuth shall be obtained on all directionally drilled wells at intervals not exceeding 500 feet during the normal course of drilling and at intervals not exceeding 200 feet in all planned angle-change portions of the borehole.
(3) Directional surveys giving both inclination and azimuth shall be obtained on both vertically and directionally drilled wells at intervals not exceeding 500 feet prior to or upon setting a string of casing, or production liner, and at total depth. Composite directional surveys shall be prepared with the interval shown from the bottom of the conductor casing. In calculating all surveys, a correction from the true north to Universal-Transverse-Mercator-Grid-north or Lambert-Grid-north shall be made after making the magnetic-to-true-north correction. A composite dipmeter directional survey or a composite measurement while-drilling directional survey will be acceptable as fulfilling the applicable requirements of this paragraph.
(4) Wells are classified as vertical if the calculated average of inclination readings weighted by the respective interval lengths between readings from surface to drilled depth does not exceed 3 degrees from the vertical. When the calculated average inclination readings weighted by the length of the respective interval between readings from the surface to drilled depth exceeds 3 degrees, the well is classified as directional.
(5) At the request of a holder of an adjoining lease, the Regional Supervisor may, for the protection of correlative rights, furnish a copy of the directional survey to that leaseholder.
(f) Fixed drilling platforms. Applications for installation of fixed drilling platforms or structures including artificial islands shall be submitted in accordance with the provisions of subpart I, Platforms and Structures, of this part. Mobile drilling units that have their jacking equipment removed or have been otherwise immobilized are classified as fixed bottom founded drilling platforms.
(g) Crane operations. You must operate a crane installed on fixed platforms according to § 250.108 of this subpart.
(h) Diesel-engine air intakes. After August 14, 1992, diesel-engine air intakes shall be equipped with a device to shut down the diesel engine in the event of runaway. Diesel engines that are continuously attended shall be equipped with either remote-operated manual or automatic-shutdown devices. Diesel engines that are not continuously attended shall be equipped with automatic shutdown devices.
[56 FR 32100, July 15, 1991, as amended at 58 FR 49928, Sept. 24, 1993. Redesignated and amended at 63 FR 29479, 29487, May 29, 1998; 63 FR 34597, June 25, 1998; 65 FR 15864, Mar. 24, 2000; 70 FR 51519, Aug. 30, 2005]
§ 250.1606
Control of wells.
The lessee shall take necessary precautions to keep its wells under control at all times. Operations shall be conducted in a safe and workmanlike manner. The lessee shall utilize the best available and safest drilling technologies and state-of-the-art methods to evaluate and minimize the potential for a well to flow or kick. The lessee shall utilize personnel who are trained and competent and shall utilize and maintain equipment and materials necessary to assure the safety and protection of personnel, equipment, natural resources, and the environment.
§ 250.1607
Field rules.
When geological and engineering information in a field enables a District Manager to determine specific operating requirements, field rules may be established for drilling, well completion, or well workover on the District Manager's initiative or in response to a request from a lessee; such rules may modify the specific requirements of this subpart. After field rules have been established, operations in the field shall be conducted in accordance with such rules and other requirements of this subpart. Field rules may be amended or canceled for cause at any time upon the initiative of the District Manager or upon the request of a lessee.
§ 250.1608
Well casing and cementing.
(a) General requirements. (1) For the purpose of this subpart, the several casing strings in order of normal installation are:
(i) Drive or structural,
(ii) Conductor,
(iii) Cap rock casing,
(iv) Bobtail cap rock casing (required when the cap rock casing does not penetrate into the cap rock),
(v) Second cap rock casing (brine wells), and
(vi) Production liner.
(2) The lessee shall case and cement all wells with a sufficient number of strings of casing cemented in a manner necessary to prevent release of fluids from any stratum through the wellbore (directly or indirectly) into the sea, protect freshwater aquifers from contamination, support unconsolidated sediments, and otherwise provide a means of control of the formation pressures and fluids. Cement composition, placement techniques, and waiting time shall be designed and conducted so that the cement in place behind the bottom 500 feet of casing or total length of annular cement fill, if less, attains a minimum compressive strength of 160 pounds per square inch (psi).
(3) The lessee shall install casing designed to withstand the anticipated stresses imposed by tensile, compressive, and buckling loads; burst and collapse pressures; thermal effects; and combinations thereof. Safety factors in the drilling and casing program designs shall be of sufficient magnitude to provide well control during drilling and to assure safe operations for the life of the well.
(4) In cases where cement has filled the annular space back to the mud line, the cement may be washed out or displaced to a depth not exceeding the depth of the structural casing shoe to facilitate casing removal upon well abandonment if the District Manager determines that subsurface protection against damage to freshwater aquifers and against damage caused by adverse loads, pressures, and fluid flows is not jeopardized.
(5) If there are indications of inadequate cementing (such as lost returns, cement channeling, or mechanical failure of equipment), the lessee shall evaluate the adequacy of the cementing operations by pressure testing the casing shoe. If the test indicates inadequate cementing, the lessee shall initiate remedial action as approved by the District Manager. For cap rock casing, the test for adequacy of cementing shall be the pressure testing of the annulus between the cap rock and the conductor casings. The pressure shall not exceed 70 percent of the burst pressure of the conductor casing or 70 percent of the collapse pressure of the cap rock casing.
(b) Drive or structural casing. This casing shall be set by driving, jetting, or drilling to a minimum depth of 100 feet below the mud line or such other depth, as may be required or approved by the District Manager, in order to support unconsolidated deposits and to provide hole stability for initial drilling operations. If this portion of the hole is drilled, a quantity of cement sufficient to fill the annular space back to the mud line shall be used.
(c) Conductor and cap rock casing setting and cementing requirements. (1) Conductor and cap rock casing design and setting depths shall be based upon relevant engineering and geologic factors including the presence or absence of hydrocarbons, potential hazards, and water depths. The proposed casing setting depths may be varied, subject to District Manager approval, to permit the casing to be set in a competent formation or through formations determined desirable to be isolated from the wellbore by casing for safer drilling operations. However, the conductor casing shall be set immediately prior to drilling into formations known to contain oil or gas or, if unknown, upon encountering such formations. Cap rock casing shall be set and cemented through formations known to contain oil or gas or, if unknown, upon encountering such formations. Upon encountering unexpected formation pressures, the lessee shall submit a revised casing program to the District Manager for approval.
(2) Conductor casing shall be cemented with a quantity of cement that fills the calculated annular space back to the mud line. Cement fill shall be verified by the observation of cement returns. In the event that observation of cement returns is not feasible, additional quantities of cement shall be used to assure fill to the mud line.
(3) Cap rock casing shall be cemented with a quantity of cement that fills the calculated annular space to at least 200 feet inside the conductor casing. When geologic conditions such as near surface fractures and faulting exist, cap rock casing shall be cemented with a quantity of cement that fills the calculated annular space to the mud line, unless otherwise approved by the District Manager. In brine wells, the second cap rock casing shall be cemented with a quantity of cement that fills the calculated annular space to at least 200 feet above the setting depth of the first cap rock casing.
(d) Bobtail cap rock casing setting and cementing requirements. (1) Bobtail cap rock casing shall be set on or just in cap rock and lapped a minimum of 100 feet into the previous casing string.
(2) Sufficient cement shall be used to fill the annular space to the top of the bobtail cap rock casing.
(e) Production liner setting and cementing requirements. (1) Production liners for sulphur wells and bleedwells shall be set in cap rock at or above the bottom of the open hole (hole that is open in cap rock, below the bottom of the cap rock casing) and lapped into the previous casing string or to the surface. For brine wells, the liner shall be set in salt and lapped into the previous casing string or to the surface.
(2) The production liner is not required to be cemented unless the cap rock contains oil or gas. If the cap rock contains oil or gas, sufficient cement shall be used to fill the annular space to the top of the production liner.
§ 250.1609
Pressure testing of casing.
(a) Prior to drilling the plug after cementing, all casing strings, except the drive or structural casing, shall be pressure tested. The conductor casing shall be tested to at least 200 psi. All casing strings below the conductor casing shall be tested to 500 psi or 0.22 psi/ft, whichever is greater. (When oil or gas is not present in the cap rock, the production liner need not be cemented in place; thus, it would not be subject to pressure testing.) If the pressure declines more than 10 percent in 30 minutes or if there is another indication of a leak, the casing shall be recemented, repaired, or an additional casing string run and the casing tested again. The above procedures shall be repeated until a satisfactory test is obtained. The time, conditions of testing, and results of all casing pressure tests shall be recorded in the driller's report.
(b) After cementing any string of casing other than structural, drilling shall not be resumed until there has been a timelapse of at least 8 hours under pressure for the conductor casing string or 12 hours under pressure for all other casing strings. Cement is considered under pressure if one or more float valves are shown to be holding the cement in place or when other means of holding pressure are used.
§ 250.1610
Blowout preventer systems and system components.
(a) General. The blowout preventer (BOP) systems and system components shall be designed, installed, used, maintained, and tested to assure well control.
(b) BOP stacks. The BOP stacks shall consist of an annular preventer and the number of ram-type preventers as specified under paragraphs (e) and (f) of this section. The pipe rams shall be of proper size to fit the drill pipe in use.
(c) Working pressure. The working-pressure rating of any BOP shall exceed the surface pressure to which it may be anticipated to be subjected.
(d) BOP equipment. All BOP systems shall be equipped and provided with the following:
(1) An accumulator system that provides sufficient capacity to supply 1.5 times the volume necessary to close and hold closed all BOP equipment units with a minimum pressure of 200 psi above the precharge pressure, without assistance from a charging system. After February 14, 1992, accumulator regulators supplied by rig air, which do not have a secondary source of pneumatic supply, shall be equipped with manual overrides or other devices alternately provided to ensure capability of hydraulic operations if rig air is lost.
(2) An automatic backup to the accumulator system. The backup system shall be supplied by a power source independent from the power source to the primary accumulator system. The automatic backup system shall possess sufficient capability to close the BOP and hold it closed.
(3) At least one operable remote BOP control station in addition to the one on the drilling floor. This control station shall be in a readily accessible location away from the drilling floor.
(4) A drilling spool with side outlets, if side outlets are not provided in the body of the BOP stack, to provide for separate kill and choke lines.
(5) A choke line and a kill line each equipped with two full-opening valves. At least one of the valves on the choke line and one valve on the kill line shall be remotely controlled, except that a check valve may be installed on the kill line in lieu of the remotely controlled valve, provided that two readily accessible manual valves are in place and the check valve is placed between the manual valve and the pump.
(6) A fill-up line above the uppermost preventer.
(7) A choke manifold designed with consideration of anticipated pressures to which it may be subjected, method of well control to be employed, surrounding environment, and corrosiveness, volume, and abrasiveness of fluids. The choke manifold shall also meet the following requirements:
(i) Manifold and choke equipment subject to well and/or pump pressure shall have a rated working pressure at least as great as the rated working pressure of the ram-type BOP's or as otherwise approved by the District Manager;
(ii) All components of the choke manifold system shall be protected from freezing by heating, draining, or filling with proper fluids; and
(iii) When buffer tanks are installed downstream of the choke assemblies for the purpose of manifolding the bleed lines together, isolation valves shall be installed on each line.
(8) Valves, pipes, flexible steel hoses, and other fittings upstream of, and including, the choke manifold with a pressure rating at least as great as the rated working pressure of the ram-type BOP's unless otherwise approved by the District Manager.
(9) A wellhead assembly with a rated working pressure that exceeds the pressure to which it might be subjected.
(10) The following system components:
(i) A kelly cock (an essentially full-opening valve) installed below the swivel and a similar valve of such design that it can be run through the BOP stack installed at the bottom of the kelly. A wrench to fit each valve shall be stored in a location readily accessible to the drilling crew;
(ii) An inside BOP and an essentially full-opening, drill-string safety valve in the open position on the rig floor at all times while drilling operations are being conducted. These valves shall be maintained on the rig floor to fit all connections that are in the drill string. A wrench to fit the drill-string safety valve shall be stored in a location readily accessible to the drilling crew;
(iii) A safety valve available on the rig floor assembled with the proper connection to fit the casing string being run in the hole; and
(iv) Locking devices installed on the ram-type preventers.
(e) BOP requirements. Prior to drilling below cap rock casing, a BOP system shall be installed consisting of at least three remote-controlled, hydraulically operated BOP's including at least one equipped with pipe rams, one with blind rams, and one annular type.
(f) Tapered drill-string operations. Prior to commencing tapered drill-string operations, the BOP stack shall be equipped with conventional and/or variable-bore pipe rams to provide either of the following:
(1) One set of variable bore rams capable of sealing around both sizes in the string and one set of blind rams, or
(2) One set of pipe rams capable of sealing around the larger size string, provided that blind-shear ram capability is present, and crossover subs to the larger size pipe are readily available on the rig floor.
§ 250.1611
Blowout preventer systems tests, actuations, inspections, and maintenance.
(a) Prior to conducting high-pressure tests, all BOP systems shall be tested to a pressure of 200 to 300 psi.
(b) Ram-type BOP's and the choke manifold shall be pressure tested with water to rated working pressure or as otherwise approved by the District Manager. Annular type BOP's shall be pressure tested with water to 70 percent of rated working pressure or as otherwise approved by the District Manager.
(c) In conjunction with the weekly pressure test of BOP systems required in paragraph (d) of this section, the choke manifold valves, upper and lower kelly cocks, and drill-string safety valves shall be pressure tested to pipe-ram test pressures. Safety valves with proper casing connections shall be actuated prior to running casing.
(d) BOP system shall be pressure tested as follows:
(1) When installed;
(2) Before drilling out each string of casing or before continuing operations in cases where cement is not drilled out;
(3) At least once each week, but not exceeding 7 days between pressure tests, alternating between control stations. If either control system is not functional, further drilling operations shall be suspended until that system becomes operable. A period of more than 7 days between BOP tests is allowed when there is a stuck drill pipe or there are pressure control operations and remedial efforts are being performed, provided that the pressure tests are conducted as soon as possible and before normal operations resume. The date, time, and reason for postponing pressure testing shall be entered into the driller's report. Pressure testing shall be performed at intervals to allow each drilling crew to operate the equipment. The weekly pressure test is not required for blind and blind-shear rams;
(4) Bind and blind-shear rams shall be actuated at least once every 7 days. Closing pressure on the blind and blind-shear rams greater than necessary to indicate proper operation of the rams is not required;
(5) Variable bore-pipe rams shall be pressure tested against all sizes of pipe in use, excluding drill collars and bottomhole tools; and
(6) Following the disconnection or repair of any well-pressure containment seal in the wellhead/BOP stack assembly. In this situation, the pressure tests may be limited to the affected component.
(e) All BOP systems shall be inspected and maintained to assure that the equipment will function properly. The BOP systems shall be visually inspected at least once each day. The manufacturer's recommended inspection and maintenance procedures are acceptable as guidelines in complying with this requirement.
(f) The lessee shall record pressure conditions during BOP tests on pressure charts, unless otherwise approved by the District Manager. The test duration for each BOP component tested shall be sufficient to demonstrate that the component is effectively holding pressure. The charts shall be certified as correct by the operator's representative at the facility.
(g) The time, date, and results of all pressure tests, actuations, inspections, and crew drills of the BOP system and system components shall be recorded in the driller's report. The BOP tests shall be documented in accordance with the following:
(1) The documentation shall indicate the sequential order of BOP and auxiliary equipment testing and the pressure and duration of each test. As an alternate, the documentation in the driller's report may reference a BOP test plan that contains the required information and is retained on file at the facility.
(2) The control station used during the test shall be identified in the driller's report.
(3) Any problems or irregularities observed during BOP and auxiliary equipment testing and any actions taken to remedy such problems or irregularities shall be noted in the driller's report.
(4) Documentation required to be entered in the driller's report may instead be referenced in the driller's report. All records, including pressure charts, driller's report, and referenced documents, pertaining to BOP tests, actuations, and inspections, shall be available for MMS review at the facility for the duration of the drilling activity. Following completion of the drilling activity, all drilling records shall be retained for a period of 2 years at the facility, at the lessee's field office nearest the OCS facility, or at another location conveniently available to the District Manager.
§ 250.1612
Well-control drills.
Well-control drills shall be conducted for each drilling crew in accordance with the requirements set forth in § 250.462 of this part or as approved by the District Manager.
[56 FR 32100, July 15, 1991. Redesignated and amended at 63 FR 29479, 29487, May 29, 1998; 68 FR 8435, Feb. 20, 2003]
§ 250.1613
Diverter systems.
(a) When drilling a conductor or cap rock hole, all drilling units shall be equipped with a diverter system consisting of a diverter sealing element, diverter lines, and control systems. The diverter system shall be designed, installed, and maintained so as to divert gases, water, mud, and other materials away from the facilities and personnel.
(b) After August 14, 1992, diverter systems shall be in compliance with the requirements of this section.
The requirements applicable to diverters that were in effect immediately prior to August 14, 1991, shall remain in effect until August 14, 1992.
(c) The diverter system shall be equipped with remote-control valves in the flow lines that can be operated from at least one remote-control station in addition to the one on the drilling floor. Any valve used in a diverter system shall be full opening. No manual or butterfly valves shall be installed in any part of a diverter system. There shall be a minimum number of turns in the vent line(s) downstream of the spool outlet flange, and the radius of curvature of turns shall be as large as practicable. Flexible hose may be used for diversion lines instead of rigid pipe if the flexible hose has integral end couplings. The entire diverter system shall be firmly anchored and supported to prevent whipping and vibrations. All diverter control equipment and lines shall be protected from physical damage from thrown and falling objects.
(d) For drilling operations conducted with a surface wellhead configuration, the following shall apply:
(1) If the diverter system utilizes only one spool outlet, branch lines shall be installed to provide downwind diversion capability, and
(2) No spool outlet or diverter line internal diameter shall be less than 10 inches, except that dual spool outlets are acceptable if each outlet has a minimum internal diameter of 8 inches, and both outlets are piped to overboard lines and that each line downstream of the changeover nipple at the spool has a minimum internal diameter of 10 inches.
(e) The diverter sealing element and diverter valves shall be pressure tested to a minimum of 200 psi when nippled upon conductor casing. No more than 7 days shall elapse between subsequent pressure tests. The diverter sealing element, diverter valves, and diverter control systems (including the remote) shall be actuation tested, and the diverter lines shall be tested for flow prior to spudding and thereafter at least once each 24-hour period alternating between control stations. All test times and results shall be recorded in the driller's report.
§ 250.1614
Mud program.
(a) The quantities, characteristics, use, and testing of drilling mud and the related drilling procedures shall be designed and implemented to prevent the loss of well control.
(b) The lessee shall comply with requirements concerning mud control, mud test and monitoring equipment, mud quantities, and safety precautions in enclosed mud handling areas as prescribed in § 250.455 through § 250.459 of this part, except that the installation of an operable degasser in the mud system as required in § 250.456(g) is not required for sulphur operations.
[56 FR 32100, July 15, 1991. Redesignated and amended at 63 FR 29479, 29487, May 29, 1998; 68 FR 8435, Feb. 20, 2003]
§ 250.1615
Securing of wells.
A downhole-safety device such as a cement plug, bridge plug, or packer shall be timely installed when drilling operations are interrupted by events such as those that force evacuation of the drilling crew, prevent station keeping, or require repairs to major drilling units or well-control equipment. The use of blind-shear rams or pipe rams and an inside BOP may be approved by the District Manager in lieu of the above requirements if cap rock casing has been set.
§ 250.1616
Supervision, surveillance, and training.
(a) The lessee shall provide onsite supervision of drilling operations at all times.
(b) From the time drilling operations are initiated and until the well is completed or abandoned, a member of the drilling crew or the toolpusher shall maintain rig-floor surveillance continuously, unless the well is secured with BOP's, bridge plugs, packers, or cement plugs.
(c) Lessee and drilling contractor personnel shall be trained and qualified in accordance with the provisions of subpart O of this part. Records of specific training that lessee and drilling contractor personnel have successfully completed, the dates of completion, and the names and dates of the courses shall be maintained at the drill site.
§ 250.1617
Application for permit to drill.
(a) Before drilling a well under an approved Exploration Plan, Development and Production Plan, or Development Operations Coordination Document, you must file Form MMS-123, APD, with the District Manager for approval. The submission of your APD must be accompanied by payment of the service fee listed in § 250.125. Before starting operations, you must receive written approval from the District Manager unless you received oral approval under § 250.140.
(b) An APD shall include rated capacities of the proposed drilling unit and of major drilling equipment. After a drilling unit has been approved for use in an MMS district, the information need not be resubmitted unless required by the District Manager or there are changes in the equipment that affect the rated capacity of the unit.
(c) An APD shall include a fully completed Form MMS-123 and the following:
(1) A plat, drawn to a scale of 2,000 feet to the inch, showing the surface and subsurface location of the well to be drilled and of all the wells previously drilled in the vicinity from which information is available. For development wells on a lease, the wells previously drilled in the vicinity need not be shown on the plat. Locations shall be indicated in feet from the nearest block line;
(2) The design criteria considered for the well and for well control, including the following:
(i) Pore pressure;
(ii) Formation fracture gradients;
(iii) Potential lost circulation zones;
(iv) Mud weights;
(v) Casing setting depths;
(vi) Anticipated surface pressures (which for purposes of this section are defined as the pressure that can reasonably be expected to be exerted upon a casing string and its related wellhead equipment). In the calculation of anticipated surface pressure, the lessee shall take into account the drilling, completion, and producing conditions. The lessee shall consider mud densities to be used below various casing strings, fracture gradients of the exposed formations, casing setting depths, and cementing intervals, total well depth, formation fluid type, and other pertinent conditions. Considerations for calculating anticipated surface pressure may vary for each segment of the well. The lessee shall include as a part of the statement of anticipated surface pressure the calculations used to determine this pressure during the drilling phase and the completion phase, including the anticipated surface pressure used for production string design; and
(vii) If a shallow hazards site survey is conducted, the lessee shall submit with or prior to the submittal of the APD, two copies of a summary report describing the geological and manmade conditions present. The lessee shall also submit two copies of the site maps and data records identified in the survey strategy.
(3) A BOP equipment program including the following:
(i) The pressure rating of BOP equipment,
(ii) A schematic drawing of the diverter system to be used (plan and elevation views) showing spool outlet internal diameter(s); diverter line lengths and diameters, burst strengths, and radius of curvature at each turn; valve type, size, working-pressure rating, and location; the control instrumentation logic; and the operating procedure to be used by personnel, and
(iii) A schematic drawing of the BOP stack showing the inside diameter of the BOP stack and the number of annular, pipe ram, variable-bore pipe ram, blind ram, and blind-shear ram preventers.
(4) A casing program including the following:
(i) Casing size, weight, grade, type of connection and setting depth, and
(ii) Casing design safety factors for tension, collapse, and burst with the assumptions made to arrive at these values.
(5) The drilling prognosis including the following:
(i) Estimated coring intervals,
(ii) Estimated depths to the top of significant marker formations, and
(iii) Estimated depths at which encounters with fresh water, sulphur, oil, gas, or abnormally pressured water are expected.
(6) A cementing program including type and amount of cement in cubic feet to be used for each casing string;
(7) A mud program including the minimum quantities of mud and mud materials, including weight materials, to be kept at the site;
(8) A directional survey program for directionally drilled wells;
(9) An H2S Contingency Plan, if applicable, and if not previously submitted; and
(10) Such other information as may be required by the District Manager.
(d) Public information copies of the APD shall be submitted in accordance with § 250.186 of this part.
[56 FR 32100, July 15, 1991, as amended at 58 FR 49928, Sept. 24, 1993. Redesignated and amended at 63 FR 29479, 29487, May 29, 1998; 64 FR 72794, Dec. 28, 1999; 71 FR 19646, Apr. 17, 2006; 71 FR 40913, July 19, 2006]
§ 250.1618
Application for permit to modify.
(a) You must submit requests for changes in plans, changes in major drilling equipment, proposals to deepen, sidetrack, complete, workover, or plug back a well, or engage in similar activities to the District Manager on Form MMS-124, Application for Permit to Modify (APM). The submission of your APM must be accompanied by payment of the service fee listed in § 250.125. Before starting operations associated with the change, you must receive written approval from the District Manager unless you received oral approval under § 250.140.
(b) The Form MMS-124 submittal shall contain a detailed statement of the proposed work that will materially change from the work described in the approved APD. Information submitted shall include the present state of the well, including the production liner and last string of casing, the well depth and production zone, and the well's capability to produce. Within 30 days after completion of the work, a subsequent detailed report of all the work done and the results obtained shall be submitted.
(c) Public information copies of Form MMS-124 shall be submitted in accordance with § 250.117 of this part.
[56 FR 32100, July 15, 1991, as amended at 58 FR 49928, Sept. 24, 1993. Redesignated and amended at 63 FR 29479, 29487, May 29, 1998; 64 FR 72794, Dec. 28, 1999; 71 FR 40913, July 19, 2006]
§ 250.1619
Well records.
(a) Complete and accurate records for each well and all well operations shall be retained for a period of 2 years at the lessee's field office nearest the OCS facility or at another location conveniently available to the District Manager. The records shall contain a description of any significant malfunction or problem; all the formations penetrated; the content and character of sulphur in each formation if cored and analyzed; the kind, weight, size, grade, and setting depth of casing; all well logs and surveys run in the wellbore; and all other information required by the District Manager in the interests of resource evaluation, prevention of waste, conservation of natural resources, protection of correlative rights, safety of operations, and environmental protection.
(b) When drilling operations are suspended or temporarily prohibited under the provisions of § 250.170 of this part, the lessee shall, within 30 days after termination of the suspension or temporary prohibition or within 30 days after the completion of any activities related to the suspension or prohibition, transmit to the District Manager duplicate copies of the records of all activities related to and conducted during the suspension or temporary prohibition on, or attached to, Form MMS-125, End of Operations Report, or Form MMS-124, Application for Permit to Modify, as appropriate.
(c) Upon request by the District Manager or Regional Supervisor, the lessee shall furnish the following:
(1) Copies of the records of any of the well operations specified in paragraph (a) of this section;
(2) Copies of the driller's report at a frequency as determined by the District Manager. Items to be reported include spud dates, casing setting depths, cement quantities, casing characteristics, mud weights, lost returns, and any unusual activities; and
(3) Legible, exact copies of reports on cementing, acidizing, analyses of cores, testing, or other similar services.
(d) As soon as available, the lessee shall transmit copies of logs and charts developed by well-logging operations, directional-well surveys, and core analyses. Composite logs of multiple runs and directional-well surveys shall be transmitted to the District Manager in duplicate as soon as available but not later than 30 days after completion of such operations for each well.
(e) If the District Manager determines that circumstances warrant, the lessee shall submit any other reports and records of operations in the manner and form prescribed by the District Manager.
[56 FR 32100, July 15, 1991, as amended at 58 FR 49928, Sept. 24, 1993. Redesignated and amended at 63 FR 29479, 29487, May 29, 1998; 64 FR 72794, Dec. 28, 1999; 72 FR 25201, May 4, 2007]
§ 250.1620
Well-completion and well-workover requirements.
(a) Lessees shall conduct well-completion and well-workover operations in sulphur wells, bleedwells, and brine wells in accordance with §§ 250.1620 through 250.1626 of this part and other provisions of this part as appropriate (see §§ 250.501 and 250.601 of this part for the definition of well-completion and well-workover operations).
(b) Well-completion and well-workover operations shall be conducted in a manner to protect against harm or damage to life (including fish and other aquatic life), property, natural resources of the OCS including any mineral deposits (in areas leased and not leased), the national security or defense, or the marine, coastal, or human environment.
[56 FR 32100, July 15, 1991. Redesignated and amended at 63 FR 29479, 29487, May 29, 1998]
§ 250.1621
Crew instructions.
Prior to engaging in well-completion or well-workover operations, crew members shall be instructed in the safety requirements of the operations to be performed, possible hazards to be encountered, and general safety considerations to protect personnel, equipment, and the environment. Date and time of safety meetings shall be recorded and available for MMS review.
§ 250.1622
Approvals and reporting of well-completion and well-workover operations.
(a) No well-completion or well-workover operation shall begin until the lessee receives written approval from the District Manager. Approval for such operations shall be requested on Form MMS-124. Approvals by the District Manager shall be based upon a determination that the operations will be conducted in a manner to protect against harm or damage to life, property, natural resources of the OCS, including any mineral deposits, the national security or defense, or the marine, coastal, or human environment.
(b) The following information shall be submitted with Form MMS-124 (or with Form MMS-123):
(1) A brief description of the well-completion or well-workover procedures to be followed;
(2) When changes in existing subsurface equipment are proposed, a schematic drawing showing the well equipment; and
(3) Where the well is in zones known to contain H2S or zones where the presence of H2S is unknown, a description of the safety precautions to be implemented.
(c)(1) Within 30 days after completion, Form MMS-125, including a schematic of the tubing and the results of any well tests, shall be submitted to the District Manager.
(2) Within 30 days after completing the well-workover operation, except routine operations, Form MMS-124 shall be submitted to the District Manager and shall include the results of any well tests and a new schematic of the well if any subsurface equipment has been changed.
[56 FR 32100, July 15, 1991, as amended at 58 FR 49928, Sept. 24, 1993. Redesignated at 63 FR 29479, May 29, 1998]
§ 250.1623
Well-control fluids, equipment, and operations.
(a) Well-control fluids, equipment, and operations shall be designed, utilized, maintained, and/or tested as necessary to control the well in foreseeable conditions and circumstances, including subfreezing conditions. The well shall be continuously monitored during well-completion and well-workover operations and shall not be left unattended at any time unless the well is shut in and secured;
(b) The following well-control fluid equipment shall be installed, maintained, and utilized:
(1) A fill-up line above the uppermost BOP,
(2) A well-control fluid-volume measuring device for determining fluid volumes when filling the hole on trips, and
(3) A recording mud-pit-level indicator to determine mud-pit-volume gains and losses. This indicator shall include both a visual and an audible warning device.
(c) When coming out of the hole with drill pipe or a workover string, the annulus shall be filled with well-control fluid before the change in fluid level decreases the hydrostatic pressure 75 psi or every five stands of drill pipe or workover string, whichever gives a lower decrease in hydrostatic pressure. The number of stands of drill pipe or workover string and drill collars that may be pulled prior to filling the hole and the equivalent well-control fluid volume shall be calculated and posted near the operator's station. A mechanical, volumetric, or electronic device for measuring the amount of well-control fluid required to fill the hole shall be utilized.
§ 250.1624
Blowout prevention equipment.
(a) The BOP system and system components and related well-control equipment shall be designed, used, maintained, and tested in a manner necessary to assure well control in foreseeable conditions and circumstances, including subfreezing conditions. The working pressure of the BOP system and system components shall equal or exceed the expected surface pressure to which they may be subjected.
(b) The minimum BOP stack for well-completion operations or for well-workover operations with the tree removed shall consist of the following:
(1) Three remote-controlled, hydraulically operated preventers including at least one equipped with pipe rams, one with blind rams, and one annular type.
(2) When a tapered string is used, the minimum BOP stack shall consist of either of the following:
(i) An annular preventer, one set of variable bore rams capable of sealing around both sizes in the string, and one set of blind rams; or
(ii) An annular preventer, one set of pipe rams capable of sealing around the larger size string, a preventer equipped with blind-shear rams, and a crossover sub to the larger size pipe that shall be readily available on the rig floor.
(c) The BOP systems for well-completion operations, or for well-workover operations with the tree removed, shall be equipped with the following:
(1) An accumulator system that provides sufficient capacity to supply 1.5 times the volume necessary to close and hold closed all BOP equipment units with a minimum pressure of 200 psi above the precharge pressure without assistance from a charging system. After February 14, 1992, accumulator regulators supplied by rig air which do not have a secondary source of pneumatic supply shall be equipped with manual overrides or alternately other devices provided to ensure capability of hydraulic operations if rig air is lost;
(2) An automatic backup to the accumulator system supplied by a power source independent from the power source to the primary accumulator system and possessing sufficient capacity to close all BOP's and hold them closed;
(3) Locking devices for the pipe-ram preventers;
(4) At least one remote BOP-control station and one BOP-control station on the rig floor; and
(5) A choke line and a kill line each equipped with two full-opening valves and a choke manifold. One of the choke-line valves and one of the kill-line valves shall be remotely controlled except that a check valve may be installed on the kill line in lieu of the remotely-controlled valve provided that two readily accessible manual valves are in place, and the check valve is placed between the manual valve and the pump.
(d) The minimum BOP-stack components for well-workover operations with the tree in place and performed through the wellhead inside of the sulphur line using small diameter jointed pipe (usually 3/4 inch to 11/4 inch) as a work string; i.e., small-tubing operations, shall consist of the following:
(1) For air line changes, the well shall be killed prior to beginning operations. The procedures for killing the well shall be included in the description of well-workover procedures in accordance with § 250.1622 of this part. Under these circumstances, no BOP equipment is required.
(2) For other work inside of the sulphur line, a tubing stripper or annular preventer shall be installed prior to beginning work.
(e) An essentially full-opening, work-string safety valve shall be maintained on the rig floor at all times during well-completion operations. A wrench to fit the work-string safety valve shall be readily available. Proper connections shall be readily available for inserting a safety valve in the work string.
[56 FR 32100, July 15, 1991. Redesignated and amended at 63 FR 29479, 29487, May 29, 1998]
§ 250.1625
Blowout preventer system testing, records, and drills.
(a) Prior to conducting high-pressure tests, all BOP systems shall be tested to a pressure of 200 to 300 psi.
(b) Ram-type BOP's and the choke manifold shall be pressure tested with water to a rated working pressure or as otherwise approved by the District Manager. Annular type BOP's shall be pressure tested with water to 70 percent of rated working pressure or as otherwise approved by the District Manager.
(c) In conjunction with the weekly pressure test of BOP systems required in paragraph (d) of this section, the choke manifold valves, upper and lower kelly cocks, and drill-string safety valves shall be pressure tested to pipe-ram test pressures. Safety valves with proper casing connections shall be actuated prior to running casing.
(d) BOP system shall be pressure tested as follows:
(1) When installed;
(2) Before drilling out each string of casing or before continuing operations in cases where cement is not drilled out;
(3) At least once each week, but not exceeding 7 days between pressure tests, alternating between control stations. If either control system is not functional, further drilling operations shall be suspended until that system becomes operable. A period of more than 7 days between BOP tests is allowed when there is a stuck drill pipe or there are pressure control operations, and remedial efforts are being performed, provided that the pressure tests are conducted as soon as possible and before normal operations resume. The time, date, and reason for postponing pressure testing shall be entered into the driller's report. Pressure testing shall be performed at intervals to allow each drilling crew to operate the equipment. The weekly pressure test is not required for blind and blind-shear rams;
(4) Blind and blind-shear rams shall be actuated at least once every 7 days. Closing pressure on the blind and blind-shear rams greater than necessary to indicate proper operation of the rams is not required;
(5) Variable bore-pipe rams shall be pressure tested against all sizes of pipe in use, excluding drill collars and bottomhole tools; and
(6) Following the disconnection or repair of any well-pressure containment seal in the wellhead/BOP stack assembly, the pressure tests may be limited to the affected component.
(e) All personnel engaged in well-completion operations shall participate in a weekly BOP drill to familiarize crew members with appropriate safety measures.
(f) The lessee shall record pressure conditions during BOP tests on pressure charts, unless otherwise approved by the District Manager. The test duration for each BOP component tested shall be sufficient to demonstrate that the component is effectively holding pressure. The charts shall be certified as correct by the operator's representative at the facility.
(g) The time, date, and results of all pressure tests, actuations, inspections, and crew drills of the BOP system and system components shall be recorded in the operations log. The BOP tests shall be documented in accordance with the following:
(1) The documentation shall indicate the sequential order of BOP and auxiliary equipment testing and the pressure and duration of each test. As an alternate, the documentation in the operations log may reference a BOP test plan that contains the required information and is retained on file at the facility.
(2) The control station used during the test shall be identified in the operations log.
(3) Any problems or irregularities observed during BOP and auxiliary equipment testing and any actions taken to remedy such problems or irregularities shall be noted in the operations log.
(4) Documentation required to be entered in the driller's report may instead be referenced in the driller's report. All records, including pressure charts, driller's report, and referenced documents, pertaining to BOP tests, actuations, and inspections shall be available for MMS review at the facility for the duration of the drilling activity. Following completion of the drilling activity, all drilling records shall be retained for a period of 2 years at the facility, at the lessee's field office nearest the OCS facility, or at another location conveniently available to the District Manager.
§ 250.1626
Tubing and wellhead equipment.
(a) No tubing string shall be placed into service or continue to be used unless such tubing string has the necessary strength and pressure integrity and is otherwise suitable for its intended use.
(b) Wellhead, tree, and related equipment shall be designed, installed, tested, used, and maintained so as to achieve and maintain pressure control.
§ 250.1627
Production requirements.
(a) The lessee shall conduct sulphur production operations in compliance with the approved Development and Production Plan requirements of §§ 250.1627 through 250.1634 of this subpart and requirements of this part, as appropriate.
(b) Production safety equipment shall be designed, installed, used, maintained, and tested in a manner to assure the safety of operations and protection of the human, marine, and coastal environments.
[56 FR 32100, July 15, 1991. Redesignated and amended at 63 FR 29479, 29487, May 29, 1998; 63 FR 34597, June 25, 1998]
§ 250.1628
Design, installation, and operation of production systems.
(a) General. All production facilities shall be designed, installed, and maintained in a manner that provides for efficiency and safety of operations and protection of the environment.
(b) Approval of design and installation features for sulphur production facilities. Prior to installation, the lessee shall submit a sulphur production system application, in duplicate, to the District Manager for approval. The application shall include information relative to the proposed design and installation features. Information concerning approved design and installation features shall be maintained by the lessee at the lessee's offshore field office nearest the OCS facility or at another location conveniently available to the District Manager. All approvals are subject to field verification. The application shall include the following:
(1) A schematic flow diagram showing size, capacity, design, working pressure of separators, storage tanks, compressor pumps, metering devices, and other sulphur-handling vessels;
(2) A schematic piping diagram showing the size and maximum allowable working pressures as determined in accordance with API RP 14E, Recommended Practice for Design and Installation of Offshore Production Platform Piping Systems;
(3) Electrical system information including a plan of each platform deck, outlining all hazardous areas classified according to API RP 500, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Division 1 and Division 2, or API RP 505, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Zone 0, Zone 1, and Zone 2, and outlining areas in which potential ignition sources are to be installed;
(4) Certification that the design for the mechanical and electrical systems to be installed were approved by registered professional engineers. After these systems are installed, the lessee shall submit a statement to the District Manager certifying that the new installations conform to the approved designs of this subpart.
(c) Hydrocarbon handling vessels associated with fuel gas system. You must protect hydrocarbon handling vessels associated with the fuel gas system with a basic and ancillary surface safety system. This system must be designed, analyzed, installed, tested, and maintained in operating condition in accordance with API RP 14C, Analysis, Design, Installation, and Testing of Basic Surface Safety Systems for Offshore Production Platforms (incorporated by reference as specified in § 250.198). If processing components are to be utilized, other than those for which Safety Analysis Checklists are included in API RP 14C, you must use the analysis technique and documentation specified therein to determine the effect and requirements of these components upon the safety system.
(d) Approval of safety-systems design and installation features for fuel gas system. Prior to installation, the lessee shall submit a fuel gas safety system application, in duplicate, to the District Manager for approval. The application shall include information relative to the proposed design and installation features. Information concerning approved design and installation features shall be maintained by the lessee at the lessee's offshore field office nearest the OCS facility or at another location conveniently available to the District Manager. All approvals are subject to field verification. The application shall include the following:
(1) A schematic flow diagram showing size, capacity, design, working pressure of separators, storage tanks, compressor pumps, metering devices, and other hydrocarbon-handling vessels;
(2) A schematic flow diagram (API RP 14C, Figure E1, incorporated by reference as specified in § 250.198) and the related Safety Analysis Function Evaluation chart (API RP 14C, subsection 4.3c, incorporated by reference as specified in § 250.198).
(3) A schematic piping diagram showing the size and maximum allowable working pressures as determined in accordance with API RP 14E, Design and lnstallation of Offshore Production Platform Piping Systems;
(4) Electrical system information including the following:
(i) A plan of each platform deck, outlining all hazardous areas classified according to API RP 500, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Division 1 and Divisions 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, and outlining areas in which potential ignition sources are to be installed;
(ii) All significant hydrocarbon sources and a description of the type of decking, ceiling, walls (e.g., grating or solid), and firewalls; and
(iii) Elementary electrical schematic of any platform safety shutdown system with a functional legend.
(5) Certification that the design for the mechanical and electrical systems to be installed was approved by registered professional engineers. After these systems are installed, the lessee shall submit a statement to the District Manager certifying that the new installations conform to the approved designs of this subpart; and
(6) Design and schematics of the installation and maintenance of all fire- and gas-detection systems including the following:
(i) Type, location, and number of detection heads;
(ii) Type and kind of alarm, including emergency equipment to be activated;
(iii) Method used for detection;
(iv) Method and frequency of calibration; and
(v) A functional block diagram of the detection system, including the electric power supply.
[53 FR 10690, Apr. 1, 1988, as amended at 61 FR 60026, Nov. 26, 1996. Redesignated at 63 FR 29479, May 29, 1998, as amended at 65 FR 219, Jan. 4, 2000; 67 FR 51760, Aug. 9, 2002]
§ 250.1629
Additional production and fuel gas system requirements.
(a) General. Lessees shall comply with the following production safety system requirements (some of which are in addition to those contained in § 250.1628 of this part).
(b) Design, installation, and operation of additional production systems, including fuel gas handling safety systems. (1) Pressure and fired vessels must be designed, fabricated, and code stamped in accordance with the applicable provisions of sections I, IV, and VIII of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (incorporated by reference as specified in 30 CFR 250.198). Pressure and fired vessels must have maintenance inspection, rating, repair, and alteration performed in accordance with the applicable provisions of the American Petroleum Institute's Pressure Vessel Inspection Code: In-Service Inspection, Rating, Repair, and Alteration, API 510 (except §§ 6.5 and 8.5) (incorporated by reference as specified in § 250.198).
(i) Pressure safety relief valves shall be designed, installed, and maintained in accordance with applicable provisions of sections I, IV, and VIII of the ANSI/ASME Boiler and Pressure Vessel Code (incorporated by reference as specified in 30 CFR 250.198). The safety relief valves shall conform to the valve-sizing and pressure-relieving requirements specified in these documents; however, the safety relief valves shall be set no higher than the maximum-allowable working pressure of the vessel. All safety relief valves and vents shall be piped in such a way as to prevent fluid from striking personnel or ignition sources.
(ii) The lessee shall use pressure recorders to establish the operating pressure ranges of pressure vessels in order to establish the pressure-sensor settings. Pressure-recording charts used to determine operating pressure ranges shall be maintained by the lessee for a period of 2 years at the lessee's field office nearest the OCS facility or at another location conveniently available to the District Manager. The high-pressure sensor shall be set no higher than 15 percent or 5 psi, whichever is greater, above the highest operating pressure of the vessel. This setting shall also be set sufficiently below (15 percent or 5 psi, whichever is greater) the safety relief valve's set pressure to assure that the high-pressure sensor sounds an alarm before the safety relief valve starts relieving. The low-pressure sensor shall sound an alarm no lower than 15 percent or 5 psi, whichever is greater, below the lowest pressure in the operating range.
(2) Engine exhaust. You must equip engine exhausts to comply with the insulation and personnel protection requirements of API RP 14C, section 4.2c(4) (incorporated by reference as specified in § 250.198). Exhaust piping from diesel engines must be equipped with spark arresters.
(3) Firefighting systems. Firefighting systems shall conform to subsection 5.2, Fire Water Systems, of API RP 14G, Recommended Practice for Fire Prevention and Control on Open Type Offshore Production Platforms, and shall be subject to the approval of the District Manager. Additional requirements shall apply as follows:
(i) A firewater system consisting of rigid pipe with firehose stations shall be installed. The firewater system shall be installed to provide needed protection, especially in areas where fuel handling equipment is located.
(ii) Fuel or power for firewater pump drivers shall be available for at least 30 minutes of run time during platform shut-in time. If necessary, an alternate fuel or power supply shall be installed to provide for this pump-operating time unless an alternate firefighting system has been approved by the District Manager;
(iii) A firefighting system using chemicals may be used in lieu of a water system if the District Manager determines that the use of a chemical system provides equivalent fire-protection control; and
(iv) A diagram of the firefighting system showing the location of all firefighting equipment shall be posted in a prominent place on the facility or structure.
(4) Fire- and gas-detection system. (i) Fire (flame, heat, or smoke) sensors shall be installed in all enclosed classified areas. Gas sensors shall be installed in all inadequately ventilated, enclosed classified areas. Adequate ventilation is defined as ventilation that is sufficient to prevent accumulation of significant quantities of vapor-air mixture in concentrations over 25 percent of the lower explosive limit. One approved method of providing adequate ventilation is a change of air volume each 5 minutes or 1 cubic foot of air-volume flow per minute per square foot of solid floor area, whichever is greater. Enclosed areas (e.g., buildings, living quarters, or doghouses) are defined as those areas confined on more than four of their six possible sides by walls, floors, or ceilings more restrictive to air flow than grating or fixed open louvers and of sufficient size to allow entry of personnel. A classified area is any area classified Class I, Group D, Division 1 or 2, following the guidelines of API RP 500, or any area classified Class I, Zone 0, Zone 1, or Zone 2, following the guidelines of API RP 505.
(ii) All detection systems shall be capable of continuous monitoring. Fire-detection systems and portions of combustible gas-detection systems related to the higher gas concentration levels shall be of the manual-reset type. Combustible gas-detection systems related to the lower gas-concentration level may be of the automatic-reset type.
(iii) A fuel-gas odorant or an automatic gas-detection and alarm system is required in enclosed, continuously manned areas of the facility that are provided with fuel gas. Living quarters and doghouses not containing a gas source and not located in a classified area do not require a gas detection system.
(iv) The District Manager may require the installation and maintenance of a gas detector or alarm in any potentially hazardous area.
(v) Fire- and gas-detection systems must be an approved type, designed and installed according to API RP 14C, API RP 14G, and either API RP 14F or API RP 14FZ (the preceding four documents incorporated by reference as specified in § 250.198).
(c) General platform operations.Safety devices shall not be bypassed or blocked out of service unless they are temporarily out of service for startup, maintenance, or testing procedures. Only the minimum number of safety devices shall be taken out of service. Personnel shall monitor the bypassed or blocked out functions until the safety devices are placed back in service. Any safety device that is temporarily out of service shall be flagged by the person taking such device out of service.
[53 FR 10690, Apr. 1, 1988, as amended at 61 FR 60026, Nov. 26, 1996. Redesignated at 63 FR 29479, May 29, 1998, as amended at 64 FR 72794, Dec. 28, 1999; 65 FR 219, Jan. 4, 2000; 67 FR 51760, Aug. 9, 2002; 68 FR 43298, July 22, 2003; 70 FR 7403, Feb. 14, 2005; 72 FR 12096, Mar. 15, 2007; 73 FR 20172, Apr. 15, 2008]
§ 250.1630
Safety-system testing and records.
(a) Inspection and testing. You must inspect and successfully test safety system devices at the interval specified below or more frequently if operating conditions warrant. Testing must be in accordance with API RP 14C, Appendix D (incorporated by reference as specified in § 250.198). For safety system devices other than those listed in API RP 14C, Appendix D, you must utilize the analysis technique and documentation specified therein for inspection and testing of these components, and the following:
(1) Safety relief valves on the natural gas feed system for power plant operations such as pressure safety valves shall be inspected and tested for operation at least once every 12 months. These valves shall be either bench tested or equipped to permit testing with an external pressure source.
(2) The following safety devices (excluding electronic pressure transmitters and level sensors) must be inspected and tested at least once each calendar month, but at no time may more than 6 weeks elapse between tests:
(i) All pressure safety high or pressure safety low, and
(ii) All level safety high and level safety low controls.
(3) The following electronic pressure transmitters and level sensors must be inspected and tested at least once every 3 months, but at no time may more than 120 days elapse between tests:
(i) All PSH or PSL, and
(ii) All LSH and LSL controls.
(4) All pumps for firewater systems shall be inspected and operated weekly.
(5) All fire- (flame, heat, or smoke) and gas-detection systems shall be inspected and tested for operation and recalibrated every 3 months provided that testing can be performed in a nondestructive manner.
(6) Prior to the commencement of production, the lessee shall notify the District Manager when the lessee is ready to conduct a preproduction test and inspection of the safety system. The lessee shall also notify the District Manager upon commencement of production in order that a complete inspection may be conducted.
(b) Records. The lessee shall maintain records for a period of 2 years for each safety device installed. These records shall be maintained by the lessee at the lessee's field office nearest the OCS facility or another location conveniently available to the District Manager. These records shall be available for MMS review. The records shall show the present status and history of each safety device, including dates and details of installation, removal, inspection, testing, repairing, adjustments, and reinstallation.
[56 FR 32100, July 15, 1991. Redesignated at 63 FR 29479, May 29, 1998, as amended at 67 FR 51761, Aug. 9, 2002]
§ 250.1631
Safety device training.
Prior to engaging in production operations on a lease and periodically thereafter, personnel installing, inspecting, testing, and maintaining safety devices shall be instructed in the safety requirements of the operations to be performed; possible hazards to be encountered; and general safety considerations to be taken to protect personnel, equipment, and the environment. Date and time of safety meetings shall be recorded and available for MMS review.
§ 250.1632
Production rates.
Each sulphur deposit shall be produced at rates that will provide economic development and depletion of the deposit in a manner that would maximize the ultimate recovery of sulphur without resulting in waste (e.g., an undue reduction in the recovery of oil and gas from an associated hydrocarbon accumulation).
§ 250.1633
Production measurement.
(a) General. Measurement equipment and security procedures shall be designed, installed, used, maintained, and tested so as to accurately and completely measure the sulphur produced on a lease for purposes of royalty determination.
(b) Application and approval. The lessee shall not commence production of sulphur until the Regional Supervisor has approved the method of measurement. The request for approval of the method of measurement shall contain sufficient information to demonstrate to the satisfaction of the Regional Supervisor that the method of measurement meets the requirements of paragraph (a) of this section.
§ 250.1634
Site security.
(a) All locations where sulphur is produced, measured, or stored shall be operated and maintained to ensure against the loss or theft of produced sulphur and to assure accurate and complete measurement of produced sulphur for royalty purposes.
(b) Evidence of mishandling of produced sulphur from an offshore lease, or tampering or falsifying any measurement of production for an offshore lease, shall be reported to the Regional Supervisor as soon as possible but no later than the next business day after discovery of the evidence of mishandling.

Subpart Q—Decommissioning Activities

Authority:
43 U.S.C. 1331 et seq.

Source:
67 FR 35406, May 17, 2002, unless otherwise noted.

General
§ 250.1700
What do the terms “decommissioning”, “obstructions”, and “facility” mean?
(a) Decommissioning means:
(1) Ending oil, gas, or sulphur operations; and
(2) Returning the lease or pipeline right-of-way to a condition that meets the requirements of regulations of MMS and other agencies that have jurisdiction over decommissioning activities.
(b) Obstructions means structures, equipment, or objects that were used in oil, gas, or sulphur operations or marine growth that, if left in place, would hinder other users of the OCS. Obstructions may include, but are not limited to, shell mounds, wellheads, casing stubs, mud line suspensions, well protection devices, subsea trees, jumper assemblies, umbilicals, manifolds, termination skids, production and pipeline risers, platforms, templates, pilings, pipelines, pipeline valves, and power cables.
(c) Facility means any installation other than a pipeline used for oil, gas, or sulphur activities that is permanently or temporarily attached to the seabed on the OCS. Facilities include production and pipeline risers, templates, pilings, and any other facility or equipment that constitutes an obstruction such as jumper assemblies, termination skids, umbilicals, anchors, and mooring lines.
[67 FR 35406, May 17, 2002; 67 FR 66047, Oct. 30, 2002]
§ 250.1701
Who must meet the decommissioning obligations in this subpart?
(a) Lessees and owners of operating rights are jointly and severally responsible for meeting decommissioning obligations for facilities on leases, including the obligations related to lease-term pipelines, as the obligations accrue and until each obligation is met.
(b) All holders of a right-of-way are jointly and severally liable for meeting decommissioning obligations for facilities on their right-of-way, including right-of-way pipelines, as the obligations accrue and until each obligation is met.
(c) In this subpart, the terms “you” or “I” refer to lessees and owners of operating rights, as to facilities installed under the authority of a lease, and to right-of-way holders as to facilities installed under the authority of a right-of-way.
§ 250.1702
When do I accrue decommissioning obligations?
You accrue decommissioning obligations when you do any of the following:
(a) Drill a well;
(b) Install a platform, pipeline, or other facility;
(c) Create an obstruction to other users of the OCS;
(d) Are or become a lessee or the owner of operating rights of a lease on which there is a well that has not been permanently plugged according to this subpart, a platform, a lease term pipeline, or other facility, or an obstruction;
(e) Are or become the holder of a pipeline right-of-way on which there is a pipeline, platform, or other facility, or an obstruction; or
(f) Re-enter a well that was previously plugged according to this subpart.
§ 250.1703
What are the general requirements for decommissioning?
When your facilities are no longer useful for operations, you must:
(a) Get approval from the appropriate District Manager before decommissioning wells and from the Regional Supervisor before decommissioning platforms and pipelines or other facilities;
(b) Permanently plug all wells;
(c) Remove all platforms and other facilities;
(d) Decommission all pipelines;
(e) Clear the seafloor of all obstructions created by your lease and pipeline right-of-way operations; and
(f) Conduct all decommissioning activities in a manner that is safe, does not unreasonably interfere with other uses of the OCS, and does not cause undue or serious harm or damage to the human, marine, or coastal environment.
§ 250.1704
When must I submit decommissioning applications and reports?
You must submit decommissioning applications and receive approval and submit subsequent reports according to the table in this section.
Decommissioning Applications and Reports Table
Decommissioning applications and reports | When to submit | Instructions
(a) Initial platform removal application [not required in the Gulf of Mexico OCS Region] | In the Pacific OCS Region or Alaska OCS Region, submit the application to the Regional Supervisor at least 2 years before production is projected to cease | Include information required under § 250.1726.
(b) Final removal application for a platform or other facility | Before removing a platform or other facility in the Gulf of Mexico OCS Region, or not more than 2 years after the submittal of an initial platform removal application to the Pacific OCS Region and the Alaska OCS Region | Include information required under § 250.1727.
(c) Post-removal report for a platform or other facility | Within 30 days after you remove a platform or other facility | Include information required under § 250.1729.
(d) Pipeline decommissioning application | Before you decommission a pipeline | Include information required under § 250.1751(a) or § 250.1752(a), as applicable.
(e) Post-pipeline decommissioning report | Within 30 days after you decommission a pipeline | Include information required under § 250.1753.
(f) Site clearance report for a platform or other facility | Within 30 days after you complete site clearance verification activities | Include information required under § 250.1743(b).
(g) Form MMS-124, Application for Permit to Modify (APM). The submission of your APM must be accompanied by payment of the service fee listed in § 250.125 | (1) Before you temporarily abandon or permanently plug a well or zone (2) Within 30 days after you plug a well * * * | Include information required under §§ 250.1712 and 250.1721. Include information required under § 250.1717.
| (3) Before you install a subsea protective device | Refer to § 250.1722(a).
| | (4) Within 30 days after you complete a protective device trawl test | Include information required under § 250.1722(d).
| (5) Before you remove any casing stub or mud line suspension equipment and any subsea protective device | Refer to § 250.1723.
| (6) Within 30 days after you complete site clearance verification activities | Include information required under § 250.1743(a).
[67 FR 35406, May 17, 2002; 67 FR 44265, July 1, 2002; 67 FR 66047, Oct. 30, 2002, as amended at 71 FR 40913, July 19, 2006]

Permanently Plugging Wells
§ 250.1710
When must I permanently plug all wells on a lease?
You must permanently plug all wells on a lease within 1 year after the lease terminates.
§ 250.1711
When will MMS order me to permanently plug a well?
MMS will order you to permanently plug a well if that well:
(a) Poses a hazard to safety or the environment; or
(b) Is not useful for lease operations and is not capable of oil, gas, or sulphur production in paying quantities.
§ 250.1712
What information must I submit before I permanently plug a well or zone?
Before you permanently plug a well or zone, you must submit form MMS-124, Application for Permit to Modify, to the appropriate District Manager and receive approval. A request for approval must contain the following information:
(a) The reason you are plugging the well (or zone), for completions with production amounts specified by the Regional Supervisor, along with substantiating information demonstrating its lack of capacity for further profitable production of oil, gas, or sulfur;
(b) Recent well test data and pressure data, if available;
(c) Maximum possible surface pressure, and how it was determined;
(d) Type and weight of well-control fluid you will use;
(e) A description of the work; and
(f) A current and proposed well schematic and description that includes:
(1) Well depth;
(2) All perforated intervals that have not been plugged;
(3) Casing and tubing depths and details;
(4) Subsurface equipment;
(5) Estimated tops of cement (and the basis of the estimate) in each casing annulus;
(6) Plug locations;
(7) Plug types;
(8) Plug lengths;
(9) Properties of mud and cement to be used;
(10) Perforating and casing cutting plans;
(11) Plug testing plans;
(12) Casing removal (including information on explosives, if used);
(13) Proposed casing removal depth; and
(14) Your plans to protect archaeological and sensitive biological features, including anchor damage during plugging operations, a brief assessment of the environmental impacts of the plugging operations, and the procedures and mitigation measures you will take to minimize such impacts.
[67 FR 35406, May 17, 2002; 67 FR 66048, Oct. 30, 2002]
§ 250.1713
Must I notify MMS before I begin well plugging operations?
You must notify the appropriate District Manager at least 48 hours before beginning operations to permanently plug a well.
§ 250.1714
What must I accomplish with well plugs?
You must ensure that all well plugs:
(a) Provide downhole isolation of hydrocarbon and sulphur zones;
(b) Protect freshwater aquifers; and
(c) Prevent migration of formation fluids within the wellbore or to the seafloor.
§ 250.1715
How must I permanently plug a well?
(a) You must permanently plug wells according to the table in this section. The District Manager may require additional well plugs as necessary.
Permanent Well Plugging Requirements
If you have— | Then you must use—
(1) Zones in open hole | Cement plug(s) set from at least 100 feet below the bottom to 100 feet above the top of oil, gas, and fresh-water zones to isolate fluids in the strata.
(2) Open hole below casing | (i) A cement plug, set by the displacement method, at least 100 feet above and below deepest casing shoe; (ii) A cement retainer with effective back-pressure control set 50 to 100 feet above the casing shoe, and a cement plug that extends at least 100 feet below the casing shoe and at least 50 feet above the retainer; or (iii) A bridge plug set 50 feet to 100 feet above the shoe with 50 feet of cement on top of the bridge plug, for expected or known lost circulation conditions.
(3) A perforated zone that is currently open and not previously squeezed or isolated | (i) A method to squeeze cement to all perforations; (ii) A cement plug set by the displacement method, at least 100 feet above to 100 feet below the perforated interval, or down to a casing plug, whichever is less; or (iii) If the perforated zones are isolated from the hole below, you may use any of the plugs specified in paragraphs (a)(3)(iii)(A) through (E) of this section instead of those specified in paragraphs (a)(3)(i) and (a)(3)(ii) of this section. (A) A cement retainer with effective back-pressure control set 50 to 100 feet above the top of the perforated interval, and a cement plug that extends at least 100 feet below the bottom of the perforated interval with at least 50 feet of cement above the retainer; (B) A bridge plug set 50 to 100 feet above the top of the perforated interval and at least 50 feet of cement on top of the bridge plug; (C) A cement plug at least 200 feet in length, set by the displacement method, with the bottom of the plug no more than 100 feet above the perforated interval; (D) A through-tubing basket plug set no more than 100 feet above the perforated interval with at least 50 feet of cement on top of the basket plug; or (E) A tubing plug set no more than 100 feet above the perforated interval topped with a sufficient volume of cement so as to extend at least 100 feet above the uppermost packer in the wellbore and at least 300 feet of cement in the casing annulus immediately above the packer.
(4) A casing stub where the stub end is within the casing | (i) A cement plug set at least 100 feet above and below the stub end; (ii) A cement retainer or bridge plug set at least 50 to 100 feet above the stub end with at least 50 feet of cement on top of the retainer or bridge plug; or (iii) A cement plug at least 200 feet long with the bottom of the plug set no more than 100 feet above the stub end.
(5) A casing stub where the stub end is below the casing | A plug as specified in paragraph (a)(1) or (a)(2) of this section, as applicable.
(6) An annular space that communicates with open hole and extends to the mud line | A cement plug at least 200 feet long set in the annular space. For a well completed above the ocean surface, you must pressure test each casing annulus to verify isolation.
(7) A subsea well with unsealed annulus | A cutter to sever the casing, and you must set a stub plug as specified in paragraphs (a)(4) and (a)(5) of this section.
(8) A well with casing | A cement surface plug at least 150 feet long set in the smallest casing that extends to the mud line with the top of the plug no more than 150 feet below the mud line.
(9) Fluid left in the hole | A fluid in the intervals between the plugs that is dense enough to exert a hydrostatic pressure that is greater than the formation pressures in the intervals.
(10) Permafrost areas | (i) A fluid to be left in the hole that has a freezing point below the temperature of the permafrost, and a treatment to inhibit corrosion; and (ii) Cement plugs designed to set before freezing and have a low heat of hydration.
(b) You must test the first plug below the surface plug and all plugs in lost circulation areas that are in open hole. The plug must pass one of the following tests to verify plug integrity:
(1) A pipe weight of at least 15,000 pounds on the plug; or
(2) A pump pressure of at least 1,000 pounds per square inch. Ensure that the pressure does not drop more than 10 percent in 15 minutes. The District Manager may require you to tests other plug(s).
[67 FR 35406, May 17, 2002; 67 FR 44265, July 1, 2002; 67 FR 66048, Oct. 30, 2002]
§ 250.1716
To what depth must I remove wellheads and casings?
(a) Unless the District Manager approves an alternate depth under paragraph (b) of this section, you must remove all wellheads and casings to at least 15 feet below the mud line.
(b) The District Manager may approve an alternate removal depth if:
(1) The wellhead or casing would not become an obstruction to other users of the seafloor or area, and geotechnical and other information you provide demonstrate that erosional processes capable of exposing the obstructions are not expected; or
(2) You determine, and MMS concurs, that you must use divers, and the seafloor sediment stability poses safety concerns; or
(3) The water depth is greater than 800 meters (2,624 feet).
§ 250.1717
After I permanently plug a well, what information must I submit?
Within 30 days after you permanently plug a well, you must submit form MMS-124, Application for Permit to Modify (subsequent report), to the appropriate District Manager, and include the following information:
(a) Information included in § 250.1712 with a final well schematic;
(b) Description of the plugging work;
(c) Nature and quantities of material used in the plugs; and
(d) If you cut and pulled any casing string, the following information:
(1) A description of the methods used (including information on explosives, if used);
(2) Size and amount of casing removed; and
(3) Casing removal depth.
[67 FR 35406, May 17, 2002; 67 FR 66049, Oct. 30, 2002]

Temporary Abandoned Wells
§ 250.1721
If I temporarily abandon a well that I plan to re-enter, what must I do?
You may temporarily abandon a well when it is necessary for proper development and production of a lease. To temporarily abandon a well, you must do all of the following:
(a) Submit form MMS-124, Application for Permit to Modify, and the applicable information required by § 250.1712 to the appropriate District Manager and receive approval;
(b) Adhere to the plugging and testing requirements for permanently plugged wells listed in the table in § 250.1715, except for § 250.1715 (a)(8). You do not need to sever the casings, remove the wellhead, or clear the site;
(c) Set a bridge plug or a cement plug at least 100-feet long at the base of the deepest casing string, unless the casing string has been cemented and has not been drilled out. If a cement plug is set, it is not necessary for the cement plug to extend below the casing shoe into the open hole;
(d) Set a retrievable or a permanent-type bridge plug or a cement plug at least 100 feet long in the inner-most casing. The top of the bridge plug or cement plug must be no more than 1,000 feet below the mud line. MMS may consider approving alternate requirements for subsea wells case-by-case;
(e) Identify and report subsea wellheads, casing stubs, or other obstructions that extend above the mud line according to U.S. Coast Guard (USCG) requirements; and
(f) Except in water depths greater than 300 feet, protect subsea wellheads, casing stubs, mud line suspensions, or other obstructions remaining above the seafloor by using one of the following methods, as approved by the District Manager or Regional Supervisor:
(1) A caisson designed according to 30 CFR 250, subpart I, and equipped with aids to navigation;
(2) A jacket designed according to 30 CFR 250, subpart I, and equipped with aids to navigation; or
(3) A subsea protective device that meets the requirements in § 250.1722.
(g) Within 30 days after you temporarily plug a well, you must submit form MMS-124, Application for Permit to Modify (subsequent report), and include the following information:
(1) Information included in § 250.1712 with a well schematic;
(2) Information required by § 250.1717(b), (c), and (d); and
(3) A description of any remaining subsea wellheads, casing stubs, mudline suspension equipment, or other obstructions that extend above the seafloor.
[67 FR 35406, May 17, 2002; 67 FR 66049, Oct. 30, 2002]
§ 250.1722
If I install a subsea protective device, what requirements must I meet?
If you install a subsea protective device under § 250.1721(f)(3), you must install it in a manner that allows fishing gear to pass over the obstruction without damage to the obstruction, the protective device, or the fishing gear.
(a) Use form MMS-124, Application for Permit to Modify to request approval from the appropriate District Manager to install a subsea protective device.
(b) The protective device may not extend more than 10 feet above the seafloor (unless MMS approves otherwise).
(c) You must trawl over the protective device when you install it (adhere to the requirements at § 250.1741 (d) through (h)). If the trawl does not pass over the protective device or causes damage to it, you must notify the appropriate District Manager within 5 days and perform remedial action within 30 days of the trawl;
(d) Within 30 days after you complete the trawling test described in paragraph (c) of this section, submit a report to the appropriate District Manager using form MMS-124, Application for Permit to Modify, that includes the following:
(1) The date(s) the trawling test was performed and the vessel that was used;
(2) A plat at an appropriate scale showing the trawl lines;
(3) A description of the trawling operation and the net(s) that were used;
(4) An estimate by the trawling contractor of the seafloor penetration depth achieved by the trawl;
(5) A summary of the results of the trawling test including a discussion of any snags and interruptions, a description of any damage to the protective covering, the casing stub or mud line suspension equipment, or the trawl, and a discussion of any snag removals requiring diver assistance; and
(6) A letter signed by your authorized representative stating that he/she witnessed the trawling test.
(e) If a temporarily abandoned well is protected by a subsea device installed in a water depth less than 100 feet, mark the site with a buoy installed according to the USCG requirements.
(f) Provide annual reports to the Regional Supervisor describing your plans to either re-enter and complete the well or to permanently plug the well.
(g) Ensure that all subsea wellheads, casing stubs, mud line suspensions, or other obstructions in water depths less than 300 feet remain protected.
(1) To confirm that the subsea protective covering remains properly installed, either conduct a visual inspection or perform a trawl test at least annually.
(2) If the inspection reveals that a casing stub or mud line suspension is no longer properly protected, or if the trawl does not pass over the subsea protective covering without causing damage to the covering, the casing stub or mud line suspension equipment, or the trawl, notify the appropriate District Manager within 5 days, and perform the necessary remedial work within 30 days of discovery of the problem.
(3) In your annual report required by paragraph (f) of this section, include the inspection date, results, and method used and a description of any remedial work you will perform or have performed.
(h) You may request approval to waive the trawling test required by paragraph (c) of this section if you plan to use either:
(1) A buoy with automatic tracking capabilities installed and maintained according to USCG requirements at 33 CFR part 67 (or its successor); or
(2) A design and installation method that has been proven successful by trawl testing of previous protective devices of the same design and installed in areas with similar bottom conditions.
[67 FR 35406, May 17, 2002; 67 FR 66049, Oct. 30, 2002]
§ 250.1723
What must I do when it is no longer necessary to maintain a well in temporary abandoned status?
If you or MMS determines that continued maintenance of a well in a temporary abandoned status is not necessary for the proper development or production of a lease, you must:
(a) Promptly and permanently plug the well according to § 250.1715;
(b) Remove any casing stub or mud line suspension equipment and any subsea protective covering. You must submit a request for approval to perform such work to the appropriate District Manager using form MMS-124, Application for Permit to Modify; and
(c) Clear the well site according to § 250.1740 through § 250.1742.
[67 FR 35406, May 17, 2002; 67 FR 66049, Oct. 30, 2002]

Removing Platforms and Other Facilities
§ 250.1725
When do I have to remove platforms and other facilities?
(a) You must remove all platforms and other facilities within 1 year after the lease or pipeline right-of-way terminates, unless you receive approval to maintain the structure to conduct other activities. Platforms include production platforms, well jackets, single-well caissons, and pipeline accessory platforms.
(b) Before you may remove a platform or other facility, you must submit a final removal application to the Regional Supervisor for approval and include the information listed in § 250.1727.
(c) You must remove a platform or other facility according to the approved application.
(d) You must flush all production risers with seawater before you remove them.
(e) You must notify the Regional Supervisor at least 48 hours before you begin the removal operations.
§ 250.1726
When must I submit an initial platform removal application and what must it include?
An initial platform removal application is required only for leases and pipeline rights-of-way in the Pacific OCS Region or the Alaska OCS Region. It must include the following information:
(a) Platform or other facility removal procedures, including the types of vessels and equipment you will use;
(b) Facilities (including pipelines) you plan to remove or leave in place;
(c) Platform or other facility transportation and disposal plans;
(d) Plans to protect marine life and the environment during decommissioning operations, including a brief assessment of the environmental impacts of the operations, and procedures and mitigation measures that you will take to minimize the impacts; and
(e) A projected decommissioning schedule.
[67 FR 35406, May 17, 2002; 67 FR 66049, Oct. 30, 2002]
§ 250.1727
What information must I include in my final application to remove a platform or other facility?
You must submit to the Regional Supervisor, a final application for approval to remove a platform or other facility. Your application must be accompanied by payment of the service fee listed in § 250.125. If you are proposing to use explosives, provide three copies of the application. If you are not proposing to use explosives, provide two copies of the application. Include the following information in the final removal application, as applicable:
(a) Identification of the applicant including:
(1) Lease operator/pipeline right-of-way holder;
(2) Address;
(3) Contact person and telephone number; and
(4) Shore base.
(b) Identification of the structure you are removing including:
(1) Platform Name/MMS Complex ID Number;
(2) Location (lease/right-of-way, area, block, and block coordinates);
(3) Date installed (year);
(4) Proposed date of removal (Month/Year); and
(5) Water depth.
(c) Description of the structure you are removing including:
(1) Configuration (attach a photograph or a diagram);
(2) Size;
(3) Number of legs/casings/pilings;
(4) Diameter and wall thickness of legs/casings/pilings;
(5) Whether piles are grouted inside or outside;
(6) Brief description of soil composition and condition;
(7) The sizes and weights of the jacket, topsides (by module), conductors, and pilings; and
(8) The maximum removal lift weight and estimated number of main lifts to remove the structure.
(d) A description, including anchor pattern, of the vessel(s) you will use to remove the structure.
(e) Identification of the purpose, including:
(1) Lease expiration/right-of-way relinquishment date; and
(2) Reason for removing the structure.
(f) A description of the removal method, including:
(1) A brief description of the method you will use;
(2) If you are using explosives, the following:
(i) Type of explosives;
(ii) Number and sizes of charges;
(iii) Whether you are using single shot or multiple shots;
(iv) If multiple shots, the sequence and timing of detonations;
(v) Whether you are using a bulk or shaped charge;
(vi) Depth of detonation below the mud line; and
(vii) Whether you are placing the explosives inside or outside of the pilings;
(3) If you will use divers or acoustic devices to conduct a pre-removal survey to detect the presence of turtles and marine mammals, a description of the proposed detection method; and
(4) A statement whether or not you will use transducers to measure the pressure and impulse of the detonations.
(g) Your plans for transportation and disposal (including as an artificial reef) or salvage of the removed platform.
(h) If available, the results of any recent biological surveys conducted in the vicinity of the structure and recent observations of turtles or marine mammals at the structure site.
(i) Your plans to protect archaeological and sensitive biological features during removal operations, including a brief assessment of the environmental impacts of the removal operations and procedures and mitigation measures you will take to minimize such impacts.
(j) A statement whether or not you will use divers to survey the area after removal to determine any effects on marine life.
[67 FR 35406, May 17, 2002, as amended at 71 FR 40913, July 19, 2006]
§ 250.1728
To what depth must I remove a platform or other facility?
(a) Unless the Regional Supervisor approves an alternate depth under paragraph (b) of this section, you must remove all platforms and other facilities (including templates and pilings) to at least 15 feet below the mud line.
(b) The Regional Supervisor may approve an alternate removal depth if:
(1) The remaining structure would not become an obstruction to other users of the seafloor or area, and geotechnical and other information you provide demonstrate that erosional processes capable of exposing the obstructions are not expected; or
(2) You determine, and MMS concurs, that you must use divers and the seafloor sediment stability poses safety concerns; or
(3) The water depth is greater than 800 meters (2,624 feet).
§ 250.1729
After I remove a platform or other facility, what information must I submit?
Within 30 days after you remove a platform or other facility, you must submit a written report to the Regional Supervisor that includes the following:
(a) A summary of the removal operation including the date it was completed;
(b) A description of any mitigation measures you took; and
(c) A statement signed by your authorized representative that certifies that the types and amount of explosives you used in removing the platform or other facility were consistent with those set forth in the approved removal application.
§ 250.1730
When might MMS approve partial structure removal or toppling in place?
The Regional Supervisor may grant a departure from the requirement to remove a platform or other facility by approving partial structure removal or toppling in place for conversion to an artificial reef or other use if you meet the following conditions:
(a) The structure becomes part of a State artificial reef program, and the responsible State agency acquires a permit from the U.S. Army Corps of Engineers and accepts title and liability for the structure; and
(b) You satisfy any U.S. Coast Guard (USCG) navigational requirements for the structure.

Site Clearance for Wells, Platforms, and Other Facilities
§ 250.1740
How must I verify that the site of a permanently plugged well, removed platform, or other removed facility is clear of obstructions?
Within 60 days after you permanently plug a well or remove a platform or other facility, you must verify that the site is clear of obstructions by using one of the following methods:
(a) For a well site, you must either:
(1) Drag a trawl over the site;
(2) Scan across the location using sonar equipment;
(3) Inspect the site using a diver;
(4) Videotape the site using a camera on a remotely operated vehicle (ROV); or
(5) Use another method approved by the District Manager if the particular site conditions warrant.
(b) For a platform or other facility site in water depths less than 300 feet, you must drag a trawl over the site.
(c) For a platform or other facility site in water depths 300 feet or more, you must either:
(1) Drag a trawl over the site;
(2) Scan across the site using sonar equipment; or
(3) Use another method approved by the Regional Supervisor if the particular site conditions warrant.
[67 FR 35406, May 17, 2002; 67 FR 66049, Oct. 30, 2002]
§ 250.1741
If I drag a trawl across a site, what requirements must I meet?
If you drag a trawl across the site in accordance with § 250.1740, you must meet all of the requirements of this section.
(a) You must drag the trawl in a grid-like pattern as shown in the following table:
For a— | You must drag the trawl across a—
(1) Well site | 300-foot-radius circle centered on the well location.
(2) Subsea well site | 600-foot-radius circle centered on the well location.
(3) Platform site | 1,320-foot-radius circle centered on the location of the platform.
(4) Single-well caisson, well protector jacket, template, or manifold | 600-foot-radius circle centered on the structure location.
(b) You must trawl 100 percent of the limits described in paragraph (a) of this section in two directions.
(c) You must mark the area to be cleared as a hazard to navigation according to USCG requirements until you complete the site clearance procedures.
(d) You must use a trawling vessel equipped with a calibrated navigational positioning system capable of providing position accuracy of ±30 feet.
(e) You must use a trawling net that is representative of those used in the commercial fishing industry (one that has a net strength equal or greater than that provided by No. 18 twine).
(f) You must ensure that you trawl no closer than 300 feet from a shipwreck, and 500 feet from a sensitive biological feature.
(g) If you trawl near an active pipeline, you must meet the requirements in the following table:
For— | You must trawl— | And you must—
(1) Buried active pipelines | | First contact the pipeline owner or operator to determine the condition of the pipeline before trawling over the buried pipeline.
(2) Unburied active pipelines that are 8 inches in diameter or larger | no closer than 100 feet to the either side of the pipeline | Trawl parallel to the pipeline Do not trawl across the pipeline.
(3) Unburied smaller diameter active pipelines in the trawl area that have obstructions (e.g., pipeline valves) present | no closer than 100 feet to either side of the pipeline. | Trawl parallel to the pipeline. Do not trawl across the pipeline.
(4) Unburied active pipelines in the trawl area that are smaller than 8 inches in diameter and have no obstructions present | parallel to the pipeline. |
(h) You must ensure that any trawling contractor you may use:
(1) Has no corporate or other financial ties to you; and
(2) Has a valid commercial trawling license for both the vessel and its captain.
[67 FR 35406, May 17, 2002; 67 FR 44266, July 1, 2002; 67 FR 66049, Oct. 30, 2002]
§ 250.1742
What other methods can I use to verify that a site is clear?
If you do not trawl a site, you can verify that the site is clear of obstructions by using any of the methods shown in the following table:
If you use— | You must— | And you must—
(a) Sonar | cover 100 percent of the appropriate grid area listed in § 250.1741(a) | Use a sonar signal with a frequency of at least 500 kHz.
(b) A diver | ensure that the diver visually inspects 100 percent of the appropriate grid area listed in § 250.1741(a) | Ensure that the diver uses a search pattern of concentric circles or parallel lines spaced no more than 10 feet apart.
(c) An ROV (remotely operated vehicle) | ensure that the ROV camera records videotape over 100 percent of the appropriate grid area listed in § 250.1741(a) | Ensure that the ROV uses a pattern of concentric circles or parallel lines spaced no more than 10 feet apart.
[67 FR 35406, May 17, 2002; 67 FR 44266, July 1, 2002]
§ 250.1743
How do I certify that a site is clear of obstructions?
(a) For a well site, you must submit to the appropriate District Manager within 30 days after you complete the verification activities a form MMS-124, Application for Permit to Modify, to include the following information:
(1) A signed certification that the well site area is cleared of all obstructions;
(2) The date the verification work was performed and the vessel used;
(3) The extent of the area surveyed;
(4) The survey method used;
(5) The results of the survey, including a list of any debris removed or a statement from the trawling contractor that no objects were recovered; and
(6) A post-trawling job plot or map showing the trawled area.
(b) For a platform or other facility site, you must submit the following information to the appropriate Regional Supervisor within 30 days after you complete the verification activities:
(1) A letter signed by an authorized company official certifying that the platform or other facility site area is cleared of all obstructions and that a company representative witnessed the verification activities;
(2) A letter signed by an authorized official of the company that performed the verification work for you certifying that they cleared the platform or other facility site area of all obstructions;
(3) The date the verification work was performed and the vessel used;
(4) The extent of the area surveyed;
(5) The survey method used;
(6) The results of the survey, including a list of any debris removed or a statement from the trawling contractor that no objects were recovered; and
(7) A post-trawling job plot or map showing the trawled area.
[67 FR 35406, May 17, 2002; 67 FR 66049, Oct. 30, 2002]

Pipeline Decommissioning
§ 250.1750
When may I decommission a pipeline in place?
You may decommission a pipeline in place when the Regional Supervisor determines that the pipeline does not constitute a hazard (obstruction) to navigation and commercial fishing operations, unduly interfere with other uses of the OCS, or have adverse environmental effects.
§ 250.1751
How do I decommission a pipeline in place?
You must do the following to decommission a pipeline in place:
(a) Submit a pipeline decommissioning application in triplicate to the Regional Supervisor for approval. Your application must be accompanied by payment of the service fee listed in § 250.125. Your application must include the following information:
(1) Reason for the operation;
(2) Proposed decommissioning procedures;
(3) Length (feet) of segment to be decommissioned; and
(4) Length (feet) of segment remaining.
(b) Pig the pipeline, unless the Regional Supervisor determines that pigging is not practical;
(c) Flush the pipeline;
(d) Fill the pipeline with seawater;
(e) Cut and plug each end of the pipeline;
(f) Bury each end of the pipeline at least 3 feet below the seafloor or cover each end with protective concrete mats, if required by the Regional Supervisor; and
(g) Remove all pipeline valves and other fittings that could unduly interfere with other uses of the OCS.
[67 FR 35406, May 17, 2002, as amended at 71 FR 40913, July 19, 2006]
§ 250.1752
How do I remove a pipeline?
Before removing a pipeline, you must:
(a) Submit a pipeline removal application in triplicate to the Regional Supervisor for approval. Your application must be accompanied by payment of the service fee listed in § 250.125. Your application must include the following information:
(1) Proposed removal procedures;
(2) If the Regional Supervisor requires it, a description, including anchor pattern(s), of the vessel(s) you will use to remove the pipeline;
(3) Length (feet) to be removed;
(4) Length (feet) of the segment that will remain in place;
(5) Plans for transportation of the removed pipe for disposal or salvage;
(6) Plans to protect archaeological and sensitive biological features during removal operations, including a brief assessment of the environmental impacts of the removal operations and procedures and mitigation measures that you will take to minimize such impacts; and
(7) Projected removal schedule and duration.
(b) Pig the pipeline, unless the Regional Supervisor determines that pigging is not practical; and
(c) Flush the pipeline.
[67 FR 35406, May 17, 2002, as amended at 71 FR 40913, July 19, 2006]
§ 250.1753
After I decommission a pipeline, what information must I submit?
Within 30 days after you decommission a pipeline, you must submit a written report to the Regional Supervisor that includes the following:
(a) A summary of the decommissioning operation including the date it was completed;
(b) A description of any mitigation measures you took; and
(c) A statement signed by your authorized representative that certifies that the pipeline was decommissioned according to the approved application.
§ 250.1754
When must I remove a pipeline decommissioned in place?
You must remove a pipeline decommissioned in place if the Regional Supervisor determines that the pipeline is an obstruction.
Pt. 251

PART 251—GEOLOGICAL AND GEOPHYSICAL (G&G) EXPLORATIONS OF THE OUTER CONTINENTAL SHELF
Sec.
251.1
Definitions.
251.2
Purpose of this part.
251.3
Authority and applicability of this part.
251.4
Types of G&G activities that require permits or Notices.
251.5
Applying for permits or filing Notices.
251.6
Obligations and rights under a permit or a Notice.
251.7
Test drilling activities under a permit.
251.8
Inspection and reporting requirements for activities under a permit.
251.9
Temporarily stopping, canceling, or relinquishing activities approved under a permit.
251.10
Penalties and appeals.
251.11
Submission, inspection, and selection of geological data and information collected under a permit and processed by permittees or third parties.
251.12
Submission, inspection, and selection of geophysical data and information collected under a permit and processed by permittees or third parties.
251.13
Reimbursement for the cost of reproducing data and information and certain processing costs.
251.14
Protecting and disclosing data and information submitted to MMS under a permit.
251.15
Authority for information collection.

Authority:
43 U.S.C. 1331 et seq., 31 U.S.C. 9701.

Source:
62 FR 67284, Dec. 24, 1997, unless otherwise noted.
§ 251.1
Definitions.
Terms used in this part have the following meaning:
Act means the Outer Continental Shelf Lands Act (OCSLA), as amended (43 U.S.C. 1331 et seq.).
Analyzed geological information means data collected under a permit or a lease that have been analyzed. Analysis may include, but is not limited to, identification of lithologic and fossil content, core analyses, laboratory analyses of physical and chemical properties, well logs or charts, results from formation fluid tests, and descriptions of hydrocarbon occurrences or hazardous conditions.
Archaeological interest means capable of providing scientific or humanistic understanding of past human behavior, cultural adaptation, and related topics through the application of scientific or scholarly techniques, such as controlled observation, contextual measurements, controlled collection, analysis, interpretation, and explanation.
Archaeological resources means any material remains of human life or activities that are at least 50 years of age and of archaeological interest.
Coastal environment means the physical, atmospheric, and biological components, conditions, and factors that interactively determine the productivity, state, condition, and quality of the terrestrial ecosystem from the shoreline inward to the boundaries of the coastal zone.
Coastal Zone means the coastal waters (including the lands therein and thereunder) and the adjacent shorelands (including the waters therein and thereunder), strongly influenced by each other and in proximity to the shorelines of the several coastal States and extends seaward to the outer limit of the U.S. territorial sea.
Coastal Zone Management Act means the Coastal Zone Management Act of 1972, as amended (16 U.S.C. 1451 et seq.).
Data means facts, statistics, measurements, or samples that have not been analyzed, processed, or interpreted.
Deep stratigraphic test means drilling that involves the penetration into the sea bottom of more than 500 feet (152 meters).
Director means the Director of the Minerals Management Service, U.S. Department of the Interior, or a subordinate authorized to act on the Director's behalf.
Exploration means the commercial search for oil, gas, and sulphur. Activities classified as exploration include, but are not limited to:
(1) Geological and geophysical marine and airborne surveys where magnetic, gravity, seismic reflection, seismic refraction, gas sniffers, coring, or other systems are used to detect or imply the presence of oil, gas, or sulphur; and
(2) Any drilling, whether on or off a geological structure.
Geological and geophysical scientific research means any oil, gas, or sulphur related investigation conducted in the OCS for scientific and/or research purposes. Geological, geophysical, and geochemical data and information gathered and analyzed are made available to the public for inspection and reproduction at the earliest practicable time. The term does not include commercial geological or geophysical exploration or research.
Geological exploration means exploration that uses geological and geochemical techniques (e.g., coring and test drilling, well logging, and bottom sampling) to produce data and information on oil, gas, and sulphur resources in support of possible exploration and development activities. The term does not include geological scientific research.
Geophysical exploration means exploration that utilizes geophysical techniques (e.g., gravity, magnetic, or seismic) to produce data and information on oil, gas, and sulphur resources in support of possible exploration and development activities. The term does not include geophysical scientific research.
Governor means the Governor of a State or the person or entity lawfully designated to exercise the powers granted to a Governor pursuant to the Act.
Human environment means the physical, social, and economic components, conditions, and factors which interactively determine the state, condition, and quality of living conditions, employment, and health of those affected, directly or indirectly, by activities occurring on the OCS.
Hydrocarbon occurrence means the direct or indirect detection during drilling operations of any liquid or gaseous hydrocarbons by examination of well cuttings, cores, gas detector readings, formation fluid tests, wireline logs, or by any other means. The term does not include background gas, minor accumulations of gas, or heavy oil residues on cuttings and cores.
Information means geological and geophysical data that have been analyzed, processed, or interpreted.
Interpreted geological information means knowledge, often in the form of schematic cross sections, 3-dimensional representations, and maps, developed by determining the geological significance of geological data and analyzed and processed geologic information.
Interpreted geophysical information means knowledge, often in the form of seismic cross sections, 3-dimensional representations, and maps, developed by determining the geological significance of geophysical data and processed geophysical information.
Lease means an agreement which is issued under section 8 or maintained under section 6 of the Act and which authorizes exploration for, and development and production of, minerals or the area covered by that authorization, whichever is required by the context.
Lessee means a person who has entered into, or is the MMS approved assignee of, a lease with the United States to explore for, develop, and produce the leased minerals. The term “lessee” also includes an owner of operating rights.
Marine environment means the physical, atmospheric, and biological components, conditions, and factors that interactively determine the quality of the marine ecosystem in the coastal zone and in the OCS.
Material remains mean physical evidence of human habitation, occupation, use, or activity, including the site, location, or context in which such evidence is situated.
Minerals mean oil, gas, sulphur, geopressured-geothermal and associated resources, and all other minerals which are authorized by an Act of Congress to be produced from public lands as defined in section 103 of the Federal Land Policy and Management Act of 1976 (43 U.S.C. 1702).
Notice means a written statement of intent to conduct geological or geophysical scientific research related to oil, gas, and sulphur in the OCS other than under a permit.
Oil, gas, and sulphur mean oil, gas, sulphur, geopressured-geothermal, and associated resources.
Outer Continental Shelf (OCS) means all submerged lands lying seaward and outside the area of lands beneath navigable waters as defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301), and of which the subsoil and seabed appertain to the United States and are subject to its jurisdiction and control.
Permit means the contract or agreement, other than a lease, issued pursuant to this part, under which a person acquires the right to conduct on the OCS, in accordance with appropriate statutes, regulations, and stipulations:
(1) Geological exploration for mineral resources;
(2) Geophysical exploration for mineral resources;
(3) Geological scientific research; or
(4) Geophysical scientific research.
Permittee means the person authorized by a permit issued pursuant to this part to conduct activities on the OCS.
Person means a citizen or national of the United States; an alien lawfully admitted for permanent residence in the United States as defined in section 8 U.S.C. 1101(a)(20); a private, public, or municipal corporation organized under the laws of the United States or of any State or territory thereof; and associations of such citizens, nationals, resident aliens, or private, public, or municipal corporations, States, or political subdivisions of States or anyone operating in a manner provided for by treaty or other applicable international agreements. The term does not include Federal agencies.
Processed geological or geophysical information means data collected under a permit and later processed or reprocessed. Processing involves changing the form of data so as to facilitate interpretation. Processing operations may include, but are not limited to, applying corrections for known perturbing causes, rearranging or filtering data, and combining or transforming data elements. Reprocessing is the additional processing other than ordinary processing used in the general course of evaluation. Reprocessing operations may include varying identified parameters for the detailed study of a specific problem area.
Secretary means the Secretary of the Interior or a subordinate authorized to act on the Secretary's behalf.
Shallow test drilling means drilling into the sea bottom to depths less than those specified in the definition of a deep stratigraphic test.
Significant archaeological resource means those archaeological resources that meet the criteria of significance for eligibility to the National Register of Historic Places as defined in 36 CFR 60.4.
Third Party means any person other than the permittee or a representative of the United States, including all persons who obtain data or information acquired under a permit from the permittee, or from another third party, by sale, trade, license agreement, or other means.
Violation means a failure to comply with any provision of the Act, or a provision of a regulation or order issued under the Act, or any provision of a lease, license, or permit issued under the Act.
You means a person who applies for and/or obtains a permit, or files a Notice to conduct geological or geophysical exploration or scientific research related to oil, gas, and sulphur in the OCS.
§ 251.2
Purpose of this part.
(a) To allow you to conduct G&G activities in the OCS related to oil, gas, and sulphur on unleased lands or on lands under lease to a third party.
(b) To ensure that you carry out G&G activities in a safe and environmentally sound manner so as to prevent harm or damage to, or waste of, any natural resources (including any mineral deposit in areas leased or not leased), any life (including fish and other aquatic life), property, or the marine, coastal, or human environment.
(c) To inform you and third parties of your legal and contractual obligations.
(d) To inform you and third parties of the U.S. Government's rights to access G&G data and information collected under permit in the OCS, reimbursement for submittal of data and information, and the proprietary terms of data and information submitted to, and retained by, MMS.
§ 251.3
Authority and applicability of this part.
MMS authorizes you to conduct exploration or scientific research activities under this part in accordance with the Act, the regulations in this part, orders of the Director/Regional Director, and other applicable statutes, regulations, and amendments.
(a) This part does not apply to G&G exploration conducted by or on behalf of the lessee on a lease in the OCS. Refer to 30 CFR part 250 if you plan to conduct G&G activities related to oil, gas, or sulphur under terms of a lease.
(b) Federal agencies are exempt from the regulations in this part.
(c) G&G exploration or G&G scientific research related to minerals other than oil, gas, and sulphur is covered by regulations at 30 CFR part 280.
§ 251.4
Types of G&G activities that require permits or Notices.
(a) Exploration. You must have an MMS-approved permit to conduct G&G exploration, including deep stratigraphic tests, for oil, gas, or sulphur resources. If you conduct both geological and geophysical exploration, you must have a separate permit for each.
(b) Scientific research. You may only conduct G&G scientific research related to oil, gas, and sulphur in the OCS after you obtain an MMS-approved permit or file a Notice.
(1) Permit. You must obtain a permit if the research activities you propose to conduct involve:
(i) Using solid or liquid explosives;
(ii) Drilling a deep stratigraphic test; or
(iii) Developing data and information for proprietary use or sale.
(2) Notice. Any other G&G scientific research that you conduct related to oil, gas, and sulphur in the OCS requires you to file a Notice with the Regional Director at least 30 days before you begin. If circumstances preclude a 30-day Notice, you must provide oral notification and followup in writing. You must also inform MMS in writing when you conclude your work.
§ 251.5
Applying for permits or filing Notices.
(a) Permits. You must submit a signed original and three copies of the MMS permit application form (Form MMS-327). The form includes names of persons, type, location, purpose, and dates of activity, and environmental and other information. A nonrefundable service fee of $1,900 must accompany your application.
(b) Disapproval of permit application. If MMS disapproves your application for a permit, the Regional Director will state the reasons for the denial and will advise you of the changes needed to obtain approval.
(c) Notices. You must sign and date a Notice and state:
(1) The name(s) of the person(s) who will conduct the proposed research;
(2) The name(s) of any other person(s) participating in the proposed research, including the sponsor;
(3) The type of research and a brief description of how you will conduct it;
(4) The location in the OCS, indicated on a map, plat, or chart, where you will conduct research;
(5) The proposed dates you project for your research activity to start and end;
(6) The name, registry number, registered owner, and port of registry of vessels used in the operation;
(7) The earliest practicable time you expect to make the data and information resulting from your research activity available to the public;
(8) Your plan of how you will make the data and information you collected available to the public;
(9) That you and others involved will not sell or withhold for exclusive use the data and information resulting from your research; and
(10) At your option, you may submit (as a substitute for the material required in paragraphs (c)(7), (c)(8), and (c)(9) of this section) the nonexclusive use agreement for scientific research attachment to Form 327.
(d) Filing locations. You must apply for a permit or file a Notice at one of the following locations:
(1) For the OCS off the State of Alaska—the Regional Supervisor for Resource Evaluation, Minerals Management Service, Alaska OCS Region, 949 East 36th Avenue, Anchorage, Alaska 99508-4302.
(2) For the OCS off the Atlantic Coast and in the Gulf of Mexico—the Regional Supervisor for Resource Evaluation, Minerals Management Service, Gulf of Mexico OCS Region, 1201 Elmwood Park Boulevard, New Orleans, Louisiana 70123-2394.
(3) For the OCS off the coast of the States of California, Oregon, Washington, or Hawaii—the Regional Supervisor for Resource Evaluation, Minerals Management Service, Pacific OCS Region, 770 Paseo Camarillo, Camarillo, California 93010-6064.
[62 FR 67284, Dec. 24, 1997, as amended at 71 FR 40913, July 19, 2006]
§ 251.6
Obligations and rights under a permit or a Notice.
While conducting G&G exploration or scientific research activities under MMS permit or Notice:
(a) You must not:
(1) Interfere with or endanger operations under any lease, right-of-way, easement, right-of-use, Notice, or permit issued or maintained under the Act;
(2) Cause harm or damage to life (including fish and other aquatic life), property, or to the marine, coastal, or human environment;
(3) Cause harm or damage to any mineral resource (in areas leased or not leased);
(4) Cause pollution;
(5) Disturb archaeological resources;
(6) Create hazardous or unsafe conditions; or
(7) Unreasonably interfere with or cause harm to other uses of the area.
(b) You must immediately report to the Regional Director if you:
(1) Detect hydrocarbon occurrences;
(2) Detect environmental hazards which imminently threaten life and property; or
(3) Adversely affect the environment, aquatic life, archaeological resources, or other uses of the area where you are conducting exploration or scientific research activities.
(c) You must also consult and coordinate your G&G activities with other users of the area for navigation and safety purposes.
(d) Any persons conducting shallow test drilling or deep stratigraphic test drilling activities under a permit must use the best available and safest technologies that the Regional Director determines to be economically feasible.
(e) You may not claim any oil, gas, sulphur, or other minerals you discover while conducting operations under a permit or Notice.
§ 251.7
Test drilling activities under a permit.
(a) Shallow test drilling. Before you begin shallow test drilling under a permit, the Regional Director may require you to:
(1) Gather and submit seismic, bathymetric, sidescan sonar, magnetometer, or other geophysical data and information to determine shallow structural detail across and in the vicinity of the proposed test.
(2) Submit information for coastal zone consistency certification according to paragraphs (b)(3) and (b)(4) of this section, and for protecting archaeological resources according to paragraph (b)(5) of this section.
(3) Allow all interested parties the opportunity to participate in the shallow test according to paragraph (c) of this section, and meet bonding requirements according to paragraph (d) of this section.
(b) Deep stratigraphic tests. You must submit to the appropriate Regional Director, at the address in § 251.5(d), a drilling plan, an environmental report, an Application for Permit to Drill (Form MMS-123), and a Supplemental APD Information Sheet (Form MMS-123S) as follows:
(1) Drilling plan. The drilling plan must include:
(i) The proposed type, sequence, and timetable of drilling activities;
(ii) A description of your drilling rig, indicating the important features with special attention to safety, pollution prevention, oil-spill containment and cleanup plans, and onshore disposal procedures;
(iii) The location of each deep stratigraphic test you will conduct, including the location of the surface and projected bottomhole of the borehole;
(iv) The types of geological and geophysical survey instruments you will use before and during drilling;
(v) Seismic, bathymetric, sidescan sonar, magnetometer, or other geophysical data and information sufficient to evaluate seafloor characteristics, shallow geologic hazards, and structural detail across and in the vicinity of the proposed test to the total depth of the proposed test well; and
(vi) Other relevant data and information that the Regional Director requires.
(2) Environmental report. The environmental report must include all of the following material:
(i) A summary with data and information available at the time you submitted the related drilling plan. MMS will consider site-specific data and information developed since the most recent environmental impact statement or other environmental impact analysis in the immediate area. The summary must meet the following requirements:
(A) You must concentrate on the issues specific to the site(s) of drilling activity. However, you only need to summarize data and information discussed in any environmental reports, analyses, or impact statements prepared for the geographic area of the drilling activity.
(B) You must list referenced material. Include brief descriptions and a statement of where the material is available for inspection.
(C) You must refer only to data that are available to MMS.
(ii) Details about your project such as:
(A) A list and description of new or unusual technologies;
(B) The location of travel routes for supplies and personnel;
(C) The kinds and approximate levels of energy sources;
(D) The environmental monitoring systems; and
(E) Suitable maps and diagrams showing details of the proposed project layout.
(iii) A description of the existing environment. For this section, you must include the following information on the area:
(A) Geology;
(B) Physical oceanography;
(C) Other uses of the area;
(D) Flora and fauna;
(E) Existing environmental monitoring systems; and
(F) Other unusual or unique characteristics that may affect or be affected by the drilling activities.
(iv) A description of the probable impacts of the proposed action on the environment and the measures you propose for mitigating these impacts.
(v) A description of any unavoidable or irreversible adverse effects on the environment that could occur.
(vi) Other relevant data that the Regional Director requires.
(3) Copies for coastal States. You must submit copies of the drilling plan and environmental report to the Regional Director for transmittal to the Governor of each affected coastal State and the coastal zone management agency of each affected coastal State that has an approved program under the Coastal Zone Management Act. (The Regional Director will make the drilling plan and environmental report available to appropriate Federal agencies and the public according to the Department of the Interior's policies and procedures).
(4) Certification of coastal zone management program consistency and State concurrence. When required under an approved coastal zone management program of an affected State, your drilling plan must include a certification that the proposed activities described in the plan comply with enforceable policies of, and will be conducted in a manner consistent with such State's program. The Regional Director may not approve any of the activities described in the drilling plan unless the State concurs with the consistency certification or the Secretary of Commerce makes the finding authorized by section 307(c)(3)(B)(iii) of the Coastal Zone Management Act.
(5) Protecting archaeological resources. If the Regional Director believes that an archaeological resource may exist in the area that may be affected by drilling, the Regional Director will notify you of the need to prepare an archaeological report.
(i) If the evidence suggests that an archaeological resource may be present, you must:
(A) Locate the site of the drilling so as to not adversely affect the area where the archaeological resources may be, or
(B) Establish to the satisfaction of the Regional Director that an archaeological resource does not exist or will not be adversely affected by drilling. This must be done by further archaeological investigation, conducted by an archaeologist and a geophysicist, using survey equipment and techniques deemed necessary by the Regional Director. A report on the investigation must be submitted to the Regional Director for review.
(ii) If the Regional Director determines that an archaeological resource is likely to be present in the area that may be affected by drilling, and may be adversely affected by drilling, the Regional Director will notify you immediately. You must take no action that may adversely affect the archaeological resource unless further investigations determine that the resource is not archaeologically significant.
(iii) If you discover any archaeological resource while drilling, you must immediately halt drilling and report the discovery to the Regional Director. If investigations determine that the resource is significant, the Regional Director will inform you how to protect it.
(6) Application for permit to drill (APD). Before commencing deep stratigraphic test drilling activities under an approved drilling plan, you must submit an APD and a Supplemental APD Information Sheet (Forms MMS-123 and MMS-123S) and receive approval. You must comply with all regulations relating to drilling operations in 30 CFR part 250.
(7) Revising an approved drilling plan. Before you revise an approved drilling plan, you must obtain the Regional Director's approval.
(8) After drilling. When you complete the test activities, you must permanently plug and abandon the boreholes of all deep stratigraphic tests in compliance with 30 CFR part 250. If the tract on which you conducted a deep stratigraphic test is leased to another party for exploration and development, and if the lessee has not disturbed the borehole, MMS will hold you and not the lessee responsible for problems associated with the test hole.
(9) Deadline for completing a deep stratigraphic test. If your deep stratigraphic test well is within 50 geographic miles of a tract that MMS has identified for a future lease sale, as listed on the currently approved OCS leasing schedule, you must complete all drilling activities and submit the data and information to the Regional Director at least 60 days before the first day of the month in which MMS schedules the lease sale. However, the Regional Director may extend your permit duration to allow you to complete drilling activities and submit data and information if the extension is in the national interest.
(c) Group participation in test drilling. MMS encourages group participation for deep stratigraphic tests.
(1) Purpose of group participation. The purpose is to minimize duplicative G&G activities involving drilling into the seabed of the OCS.
(2) Providing opportunity for participation in a deep stratigraphic test. When you propose to drill a deep stratigraphic test, you must give all interested persons an opportunity to participate in the test drilling through a signed agreement on a cost-sharing basis. You may include a penalty for late participation of not more than 100 percent of the cost to each original participant in addition to the original share cost.
(i) The participants must assess and distribute late participation penalties in accordance with the terms of the agreement.
(ii) For a significant hydrocarbon occurrence that the Regional Director announces to the public, the penalty for subsequent late participants may be raised to not more than 300 percent of the cost of each original participant in addition to the original share cost.
(3) Providing opportunity for participation in a shallow test drilling project. When you apply to conduct shallow test drilling activities, you must, if ordered by the Regional Director or required by the permit, give all interested persons an opportunity to participate in the test activity on a cost-sharing basis. You may include a penalty provision for late participation of not more than 50 percent of the cost to each original participant in addition to the original share cost.
(4) Procedures for group participation in drilling activities. You must:
(i) Publish a summary statement that describes the approved activity in a relevant trade publication;
(ii) Forward a copy of the published statement to the Regional Director;
(iii) Allow at least 30 days from the summary statement publication date for other persons to join as original participants;
(iv) Compute the estimated cost by dividing the estimated total cost of the program by the number of original participants; and
(v) Furnish the Regional Director with a complete list of all participants before starting operations, or at the end of the advertising period if you begin operations before the advertising period is over. The names of any subsequent or late participants must also be furnished to the Regional Director.
(5) Changes to the original application for test drilling. If you propose changes to the original application and the Regional Director determines that the changes are significant, the Regional Director will require you to publish the changes for an additional 30 days to give other persons a chance to join as original participants.
(d) Bonding requirements. You must submit a bond under this part before you may start a deep stratigraphic test.
(1) Before MMS issues a permit authorizing the drilling of a deep stratigraphic test, you must either:
(i) Furnish to MMS a bond of not less than $200,000 that guarantees compliance with all the terms and conditions of the permit; or
(ii) Maintain a $1 million bond that guarantees compliance with all the terms and conditions of the permit you hold for the OCS area where you propose to drill.
(2) You must provide additional security to MMS if the Regional Director determines that it is necessary for the permit or area.
(3) The Regional Director may require you to provide a bond, in an amount the Regional Director prescribes, before authorizing you to drill a shallow test well.
(4) Your bond must be on a form approved by the Associate Director for Offshore Minerals Management.
[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998, as amended at 72 FR 25202, May 4, 2007]
§ 251.8
Inspection and reporting requirements for activities under a permit.
(a) Inspection of permit activities. You must allow MMS representatives to inspect your exploration or scientific research activities under a permit. They will determine whether operations are adversely affecting the environment, aquatic life, archaeological resources, or other uses of the area. MMS will reimburse you for food, quarters, and transportation that you provide for MMS representatives if you send in your reimbursement request to the Region that issued the permit within 90 days of the inspection.
(b) Approval for modifications. Before you begin modified operations, you must submit a written request describing the modifications and receive the Regional Director's oral or written approval. If circumstances preclude a written request, you must make an oral request and follow up in writing.
(c) Reports. (1) You must submit status reports on a schedule specified in the permit and include a daily log of operations.
(2) You must submit a final report of exploration or scientific research activities under a permit within 30 days after the completion of acquisition activities under the permit. You may combine the final report with the last status report and must include each of the following:
(i) A description of the work performed.
(ii) Charts, maps, plats, and digital navigational data in a format specified by the Regional Director, showing the areas and blocks in which any exploration or permitted scientific research activities were conducted. Identify the lines of geophysical traverses and their locations including a reference sufficient to identify the data produced during each activity.
(iii) The dates on which you conducted the actual exploration or scientific research activities.
(iv) A summary of any:
(A) Hydrocarbon or sulphur occurrences encountered;
(B) Environmental hazards; and
(C) Adverse effects of the exploration or scientific research activities on the environment, aquatic life, archaeological resources, or other uses of the area in which the activities were conducted.
(v) Other descriptions of the activities conducted as specified by the Regional Director.
§ 251.9
Temporarily stopping, canceling, or relinquishing activities approved under a permit.
(a) MMS may temporarily stop exploration or scientific research activities under a permit when the Regional Director determines that:
(1) Activities pose a threat of serious, irreparable, or immediate harm. This includes damage to life (including fish and other aquatic life), property, any mineral deposit (in areas leased or not leased), to the marine, coastal, or human environment, or to an archaeological resource;
(2) You failed to comply with any applicable law, regulation, order, or provision of the permit. This would include MMS' required submission of reports, well records or logs, and G&G data and information within the time specified; or
(3) Stopping the activities is in the interest of national security or defense.
(b) Procedures to temporarily stop activities. (1) The Regional Director will advise you either orally or in writing. MMS will confirm an oral notification in writing and deliver all written notifications by courier or certified or registered mail. You must halt all activities under a permit as soon as you receive an oral or written notification.
(2) The Regional Director will advise you when you may start your permit activities again.
(c) Procedure to cancel or relinquish a permit. The Regional Director may cancel, or a permittee may relinquish, a permit at any time.
(1) If MMS cancels your permit, the Regional Director will advise you by certified or registered mail 30 days before the cancellation date and will state the reason.
(2) You may relinquish the permit by advising the Regional Director by certified or registered mail 30 days in advance.
(3) After MMS cancels your permit or you relinquish it, you are still responsible for proper abandonment of any drill sites in accordance with the requirements of § 251.7(b)(8). You must also comply with all other obligations specified in this part or in the permit.
§ 251.10
Penalties and appeals.
(a) Penalties for noncompliance under a permit issued by MMS. You are subject to the penalty provisions of: (1) Section 24 of the Act (43 U.S.C. 1350); and (2) The procedures contained in 30 CFR part 250, subpart N, for noncompliance with: (i) Any provision of the Act; (ii) Any provision of a G&G or drilling permit; or (iii) Any regulation or order issued under the Act.
(b) Penalties under other laws and regulations. The penalties prescribed in this section are in addition to any other penalty imposed by any other law or regulation.
(c) Procedures to appeal orders or decisions MMS issues. See 30 CFR part 290 for instructions on how to appeal any order or decision that we issue under this part.
[62 FR 67284, Dec. 24, 1997, as amended at 65 FR 3856, Jan. 25, 2000]
§ 251.11
Submission, inspection, and selection of geological data and information collected under a permit and processed by permittees or third parties.
(a) Availability of geological data and information collected under a permit. (1) You must notify the Regional Director, in writing, when you complete the initial analysis, processing, or interpretation of any geological data and information. Initial analysis and processing are the stages of analysis or processing where the data and information first become available for in-house interpretation by the permittee, or become available commercially to third parties via sale, trade, license agreement, or other means.
(2) The Regional Director may ask if you have further analyzed, processed, or interpreted any geological data and information. When so asked, you must respond to MMS in writing within 30 days.
(b) Submission, inspection, and selection of geological data and information. The Regional Director may request the permittee or third party to submit the analyzed, processed, and interpreted geologic data and information for inspection and/or permanent retention by MMS. The data and information must be submitted within 30 days after such request.
(c) Requirements for submission of geological data and information collected under a permit. Unless the Regional Director specifies otherwise, geological data and information must include:
(1) An accurate and complete record of all geological (including geochemical) data and information describing each operation of analysis, processing, and interpretation;
(2) Paleontological reports identifying microscopic fossils by depth, including the reference datum to which paleontological sample depths are related and, if the Regional Director requests, washed samples that you maintain for paleontological determinations;
(3) Copies of well logs or charts in a digital format, if available;
(4) Results and data obtained from formation fluid tests;
(5) Analyses of core or bottom samples and/or a representative cut or split of the core or bottom sample;
(6) Detailed descriptions of any hydrocarbons or hazardous conditions encountered during operations, including near losses of well control, abnormal geopressures, and losses of circulation; and
(7) Other geological data and information that the Regional Director may specify.
(d) Obligations when geological data and information collected under permit are obtained by a third party. A third party may obtain geological data and information from a permittee, or from another third party, by sale, trade, license agreement, or other means. If this happens:
(1) The third party recipient of the data and information assumes the obligations under this section, except for the notification provisions of paragraph (a)(1), and is subject to the penalty provisions of 30 CFR part 250, subpart N; and
(2) A permittee or third party that sells, trades, licenses, or otherwise provides data and information to a third party must advise the recipient, in writing, that accepting these obligations is a condition precedent of the sale, trade, license, or other agreement; and
(3) Except for license agreements, a permittee or third party that sells, trades, or otherwise provides data and information to a third party must advise the Regional Director, in writing and within 30 days, of the sale, trade, or other agreement, including the identity of the recipient of the data and information; or
(4) For license agreements a permittee or third party that licenses data and information to a third party must, within 30 days of a request by the Regional Director, advise the Regional Director, in writing, of the license agreement, including the identity of the recipient of the data and information.
§ 251.12
Submission, inspection, and selection of geophysical data and information collected under a permit and processed by permittees or third parties.
(a) Availability of geophysical data and information collected under a permit. (1) You must notify the Regional Director, in writing, when you complete the initial processing and interpretation of any geophysical data and information. Initial processing is the stage of processing where the data and information become available for in-house interpretation by the permittee, or become available commercially to third parties via sale, trade, license agreement, or other means.
(2) The Regional Director may ask if you have further processed or interpreted any geophysical data and information. When so asked, you must respond to MMS in writing within 30 days.
(b) Submission, inspection and selection of geophysical data and information collected under a permit. The Regional Director may request that the permittee or third party submit geophysical data and information before making a final selection for retention. MMS representatives may inspect and select the data and information on your premises, or the Regional Director can request delivery of the data and information to the appropriate MMS regional office for review.
(1) You must submit the geophysical data and information within 30 days of receiving the request, unless the Regional Director extends the delivery time.
(2) At any time before final selection, the Regional Director may return any or all geophysical data and information following review. You will be notified in writing of all or portions of those data the Regional Director decides to retain.
(c) Requirements for submission of geophysical data and information collected under a permit. Unless the Regional Director specifies otherwise, you must include:
(1) An accurate and complete record of each geophysical survey conducted under the permit, including digital navigational data and final location maps;
(2) All seismic data collected under a permit presented in a format and of a quality suitable for processing;
(3) Processed geophysical information derived from seismic data with extraneous signals and interference removed, presented in a quality format suitable for interpretive evaluation, reflecting state-of-the-art processing techniques; and
(4) Other geophysical data, processed geophysical information, and interpreted geophysical information including, but not limited to, shallow and deep subbottom profiles, bathymetry, sidescan sonar, gravity and magnetic surveys, and special studies such as refraction and velocity surveys.
(d) Obligations when geophysical data and information collected under a permit are obtained by a third party. A third party may obtain geophysical data, processed geophysical information, or interpreted geophysical information from a permittee, or from another third party, by sale, trade, license agreement, or other means. If this happens:
(1) The third party recipient of the data and information assumes the obligations under this section, except for the notification provisions of paragraph (a)(1), and is subject to the penalty provisions of 30 CFR part 250, subpart N; and
(2) A permittee or third party that sells, trades, licenses, or otherwise provides data and information to a third party must advise the recipient, in writing, that accepting these obligations is a condition precedent of the sale, trade, license, or other agreement; and
(3) Except for license agreements, a permittee or third party that sells, trades, or otherwise provides data and information to a third party must advise the Regional Director, in writing and within 30 days, of the sale, trade, or other agreement, including the identity of the recipient of the data and information; or
(4) For license agreements, a permittee or third party that licenses data and information to a third party must, within 30 days of a request by the Regional Director, advise the Regional Director, in writing, of the license agreement, including the identity of the recipient of the data and information.
§ 251.13
Reimbursement for the costs of reproducing data and information and certain processing costs.
(a) MMS will reimburse you or a third party for reasonable costs of reproducing data and information that the Regional Director requests if:
(1) You deliver G&G data and information to MMS for the Regional Director to inspect or select and retain (according to §§ 251.11 or 251.12 );
(2) MMS receives your request for reimbursement and the Regional Director determines that the requested reimbursement is proper; and
(3) The cost is at your lowest rate (or a third party's) or at the lowest commercial rate established in the area, whichever is less.
(b) MMS will reimburse you or the third party for the reasonable costs of processing geophysical information (which does not include cost of data acquisition):
(1) If, at the request of the Regional Director, you processed the geophysical data or information in a form or manner other than that used in the normal conduct of business; or
(2) If you collected the information under a permit that MMS issued to you before October 1, 1985, and the Regional Director requests and retains the information.
(c) When you request reimbursement, you must identify reproduction and processing costs separately from acquisition costs.
(d) MMS will not reimburse you or a third party for data acquisition costs or for the costs of analyzing or processing geological information or interpreting geological or geophysical information.
§ 251.14
Protecting and disclosing data and information submitted to MMS under a permit.
(a) Disclosure of data and information to the public by MMS. (1) In making data and information available to the public, the Regional Director will follow the applicable requirements of:
(i) The Freedom of Information Act (5 U.S.C. 552);
(ii) The implementing regulations at 43 CFR part 2;
(iii) The Act; and
(iv) The regulations at 30 CFR parts 250 and 252.
(2) Except as specified in this section or in 30 CFR parts 250 and 252, if the Regional Director determines any data or information is exempt from public disclosure under paragraph (a) of this section, MMS will not provide the data and information to any State or to the executive of any local government or to the public, unless you and all third parties agree to the disclosure.
(3) MMS will keep confidential the identity of third party recipients of data and information collected under a permit. MMS will not release the identity unless you and the third parties agree to the disclosure.
(4) When you detect any significant hydrocarbon occurrences or environmental hazards on unleased lands during drilling operations, the Regional Director will immediately issue a public announcement. The announcement must further the national interest, but without unduly damaging your competitive position.
(b) Timetable for release of G&G data and information that MMS acquires. Except for high-resolution data and information released under 30 CFR 250.197(b)(2), MMS will release or disclose data and information that you or a third party submit and MMS retains in accordance with paragraphs (b)(1), (b)(2), and (b)(3) of this section.
(1) If the data and information are not related to a deep stratigraphic test, MMS will release them to the public in accordance with the following table:
If you or a third party submit and MMS retains * * * | The Regional Director will release them to the public * * *
(i) Geological data and information | 10 years after MMS issues the permit.
(ii) Geophysical data | 50 years after MMS issues the permit.
(iii) Geophysical information | 25 years after MMS issues the permit.
(2) If the data and information are related to a deep stratigraphic test, MMS will release them to the public at the earlier of the following times:
(i) Twenty-five years after you complete the test; or
(ii) If a lease sale is held after you complete a test well, 60 calendar days after MMS issues the first lease, any portion of which is located within 50 geographic miles (92.7 kilometers) of the test.
(3) MMS may allow limited inspection, but only by persons with a direct interest in related MMS decisions and issues in specific geographic areas, and who agree in writing to its confidentiality, of G&G data and information submitted under this part that MMS uses to:
(i) Make unitization determinations on two or more leases;
(ii) Make competitive reservoir determinations;
(iii) Ensure proper plans of development for competitive reservoirs;
(iv) Promote operational safety;
(v) Protect the environment;
(vi) Make field determinations; or
(vii) Determine eligibility for royalty relief.
(c) Procedure that MMS follows to disclose acquired data and information to a contractor for reproduction, processing, and interpretation. (1) When practical, the Regional Director will advise the person who submitted data and information under §§ 251.11 or 251.12 of the intent to disclose the data or information to an independent contractor or agent.
(2) The person so notified will have at least 5 working days to comment on the action.
(3) When the Regional Director advises the person who submitted the data and information, all other owners of the data or information will be considered to have been so notified.
(4) Before disclosure, the contractor or agent must sign a written commitment not to sell, trade, license, or disclose data or information to anyone without the Regional Director's consent.
(d) Sharing data and information with coastal States. (1) When MMS solicits nominations for leasing lands located within 3 geographic miles (5.6 kilometers) of the seaward boundary of any coastal State, the Regional Director, in accordance with 30 CFR 252.7 (a)(4) and (b) and subsections 8(g) and 26(e) of the Act (43 U.S.C. 1337(g) and 1352(e)), will provide the Governor with:
(i) All information on the geographical, geological, and ecological characteristics of the areas and regions MMS proposes to offer for lease;
(ii) An estimate of the oil and gas reserves in the areas proposed for leasing; and
(iii) An identification of any field, geological structure, or trap on the OCS within 3 geographic miles (5.6 kilometers) of the seaward boundary of the State.
(2) After receiving nominations for leasing an area of the OCS within 3 geographic miles of the seaward boundary of any coastal State, MMS will carry out a tentative area identification according to 30 CFR part 256, subparts D and E. At that time, the Regional Director will consult with the Governor to determine whether any tracts further considered for leasing may contain any oil or gas reservoirs that underlie both the OCS and lands subject to the jurisdiction of the State.
(3) Before a sale, if a Governor requests, the Regional Director, in accordance with 30 CFR 252.7(a)(4) and (b) and sections 8(g) and 26(e) of the Act (43 U.S.C. 1337(g) and 1352(e)), will share with the Governor information that identifies potential and/or proven common hydrocarbon bearing areas within 3 geographic miles of the seaward boundary of that State.
(4) Information received and knowledge gained by a State official under paragraph (d) of this section is subject to applicable confidentiality requirements of:
(i) The Act; and
(ii) The regulations at 30 CFR parts 250, 251, and 252.
[62 FR 67284, Dec. 24, 1997, as amended at 71 FR 16039, Mar. 30, 2006; 71 FR 62050, Oct. 20, 2006; 72 FR 25202, May 4, 2007]
§ 251.15
Authority for information collection.
(a) The Office of Management and Budget has approved the information collection requirements in this part under 44 U.S.C. 3501 et seq. and assigned OMB control number 1010-0048. The title of this information collection is “30 CFR Part 251, Geological and Geophysical (G&G) Explorations of the OCS.”
(b) We may not conduct or sponsor, and you are not required to respond to, a collection of information unless it displays a currently valid OMB control number.
(c) We use the information collected under this part to:
(1) Evaluate permit applications and monitor scientific research activities for environmental and safety reasons.
(2) Determine that explorations do not harm resources, result in pollution, create hazardous or unsafe conditions, or interfere with other users in the area.
(3) Approve reimbursement of certain expenses.
(4) Monitor the progress and activities carried out under an OCS G&G permit.
(5) Inspect and select G&G data and information collected under an OCS G&G permit.
(d) Respondents are Federal OCS permittees and Notice filers. Responses are mandatory or are required to obtain or retain a benefit. We will protect information considered proprietary under applicable law and under regulations at § 251.14 and part 250 of this chapter.
(e) Send comments regarding any aspect of the collection of information under this part, including suggestions for reducing the burden, to the Information Collection Clearance Officer, Minerals Management Service, Mail Stop 4230, 1849 C Street, NW., Washington, DC 20240.
[62 FR 67284, Dec. 24, 1997, as amended at 65 FR 2875, Jan. 19, 2000]
Pt. 252

PART 252—OUTER CONTINENTAL SHELF (OCS) OIL AND GAS INFORMATION PROGRAM
Sec.
252.1
Purpose.
252.2
Definitions.
252.3
Oil and gas data and information to be provided for use in the OCS Oil and Gas Information Program.
252.4
Summary Report to affected States.
252.5
Information to be made available to affected States.
252.6
Freedom of Information Act requirements.
252.7
Privileged and proprietary data and information to be made available to affected States.

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

Source:
44 FR 46408, Aug. 7, 1979, unless otherwise noted.
§ 252.1
Purpose.
The purpose of this part is to implement the provisions of section 26 of the Act (43 U.S.C. 1352). This part supplements the procedures and requirements contained in parts 250 and 251 of this chapter and provides procedures and requirements for the submission of oil and gas data and information resulting from exploration, development, and production operations on the Outer Continental Shelf (OCS) to the Director, Minerals Management Service. In addition, this part establishes procedures for the Director to make available certain information to the Governors of affected States and, upon request, to the executives of affected local governments in accordance with the provisions of the Freedom of Information Act and the Act.
§ 252.2
Definitions.
When used in the regulations in this part, the following terms shall have the meanings given below:
(a) Act refers to the Outer Continental Shelf Lands Act, as amended (43 U.S.C. 1331 et seq.).
(b) Affected local government means the principal governing body of a locality which is in an affected State and is identified by the Governor of that State as a locality which will be significantly affected by oil and gas activities on the OCS.
(c) Affected State means, with respect to any program, plan, lease sale, or other activity, proposed, conducted, or approved pursuant to the provisions of the Act, any State:
(1) The laws of which are declared, pursuant to section 4(a)(2)(A) of the Act, to be the law of the United States for the portion of the OCS on which such activity is, or is proposed to be, conducted;
(2) Which is, or is proposed to be, directly connected by transportation facilities to any artificial island or installations and other devices permanently, or temporarily attached to the seabed;
(3) Which is receiving, or in accordance with the proposed activity will receive, oil for processing, refining, or transshipment which was extracted from the OCS and transported directly to such State by means of vessels or by a combination of means including vessels;
(4) Which is designated by the Director as a State in which there is a substantial probability of significant impact on or damage to the coastal, marine, or human environment, or a State in which there will be significant changes in the social, governmental, or economic infrastructure, resulting from the exploration, development, and production of oil and gas anywhere on the OCS; or
(5) In which the Director finds that because of such activity there is, or will be, a significant risk of serious damage, due to factors such as prevailing winds and currents, to the marine or coastal environment in the event of any oilspill, blowout, or release of oil or gas from vessels, pipelines, or other transshipment facilities.
(d) Analyzed geological information means data collected under a permit or a lease which have been analyzed. Analysis may include, but is not limited to, identification of lithologic and fossil content, core analyses, laboratory analyses of physical and chemical properties, logs or charts of electrical, radioactive, sonic, and other well logs, and descriptions of hydrocarbon shows or hazardous conditions.
(e) Area adjacent to a State means all of that portion of the OCS included within a planning area if such planning area is bordered by that State. The portion of the OCS in the Navarin Basin Planning Area is deemed to be adjacent to the State of Alaska. The States of New York and Rhode Island are deemed to be adjacent to both the Mid-Atlantic Planning Area and the North Atlantic Planning Area.
(f) Data means facts and statistics or samples which have not been analyzed or processed.
(g) Development means those activities which take place following discovery of oil or natural gas in paying quantities, including geophysical activity, drilling, platform construction, and operation of all onshore support facilities, and which are for the purpose of ultimately producing the oil and gas discovered.
(h) Director means the Director of the Minerals Management Service of the U.S. Department of the Interior or a designee of the Director.
(i) Exploration means the process of searching for oil and natural gas, including: (1) Geophysical surveys where magnetic, gravity, seismic, or other systems are used to detect or imply the presence of such oil or natural gas, and (2) any drilling, whether on or off known geological structures, including the drilling of a well in which a discovery of oil or natural gas in paying quantities is made and the drilling of any additional delineation well after such discovery which is needed to delineate any reservoir and to enable the lessee to determine whether to proceed with development and production.
(j) Governor means the Governor of a State, or the person or entity designated by, or pursuant to, State law to exercise the powers granted to a Governor pursuant to the Act.
(k) Information, when used without a qualifying adjective, includes analyzed geological information, processed geophysical information, interpreted geological information, and interpreted geophysical information.
(l) Interpreted geological information means knowledge, often in the form of schematic cross sections and maps, developed by determining the geological significance of data and analyzed geological information.
(m) Interpreted geophysical information means knowledge, often in the form of schematic cross sections and maps, developed by determining the geological significance of geophysical data and processed geophysical information.
(n) Lease means any form of authorization which is issued under section 8 or maintained under section 6 of the Act and which authorizes exploration for, and development and production of, oil or natural gas, or the land covered by such authorization, whichever is required by the context.
(o) Lessee means the party authorized by a lease, or an approved assignment thereof, to explore for and develop and produce the leased deposits in accordance with the regulations in part 250 of this chapter, including all parties holding such authority by or through the lessee.
(p) Outer Continental Shelf (OCS) means all submerged lands which lie seaward and outside of the area of lands beneath navigable waters as defined in the Submerged Lands Act (67 Stat. 29) and of which the subsoil and seabed appertain to the United States and are subject to its jurisdiction and control.
(q) Permittee means the party authorized by a permit issued pursuant to part 251 of this chapter to conduct activities on the OCS.
(r) Processed geophysical information means data collected under a permit or a lease which have been processed. Processing involves changing the form of data so as to facilitate interpretation. Processsing operations may include, but are not limited to, applying corrections for known perturbing causes, rearranging or filtering data, and combining or transforming data elements.
(s) Production means those activities which take place after the successful completion of any means for the removal of oil or natural gas, including such removal, field operations, transfer of oil or natural gas to shore, operation monitoring, maintenance, and workover drilling.
(t) Secretary means the Secretary of the Interior or a designee of the Secretary.
[44 FR 46408, Aug. 7, 1979, as amended at 49 FR 10670, Mar. 22, 1984; 51 FR 10382, Mar. 26, 1986]
§ 252.3
Oil and gas data and information to be provided for use in the OCS Oil and Gas Information Program.
(a) Any permittee or lessee engaging in the activities of exploration for, or development and production of, oil and gas on the OCS shall provide the Director access to all data and information obtained or developed as a result of such activities, including geological data, geophysical data, analyzed geological information, processed and reprocessed geophysical information, interpreted geophysical information, and interpreted geological information. Copies of these data and information and any interpretation of these data and information shall be provided to the Director upon request. No permittee or lessee submitting an interpretation of data or information, where such interpretation has been submitted in good faith, shall be held responsible for any consequence of the use of or reliance upon such interpretation.
(b)(1) Whenever a lessee or permittee provides any data or information, at the request of the Director and specifically for use in the OCS Oil and Gas Information Program in a form and manner of processing which is utilized by the lessee or permittee in the normal conduct of business, the Director shall pay the reasonable cost of reproducing the data and information if the lessee or permittee requests reimbursement. The cost shall be computed and paid in accordance with the applicable provisions of paragraph (e)(1) of this section.
(2) Whenever a lessee or permittee provides any data or information, at the request of the Director and specifically for use in the OCS Oil and Gas Information Program, in a form and manner of processing not normally utilized by the lessee or permittee in the normal conduct of business, the Director shall pay the lessee or permittee, if the lessee or permittee requests reimbursement, the reasonable cost of processing and reproducing the requested data and information. The cost is to be computed and paid in accordance with the applicable provisions of paragraph (e)(2) of this section.
(c) Data or information requested by the Director shall be provided as soon as practicable, but not later than 30 days following receipt of the Director's request, unless, for good reason, the Director authorizes a longer time period for the submission of the requested data or information.
(d) The Director reserves the right to disclose any data or information acquired from a lessee or permittee to an independent contractor or agent for the purpose of reproducing, processing, reprocessing, or interpreting such data or information. When practicable, the Director shall notify the lessee(s) or permittee(s) who provided the data or information of the intent to disclose the data or information to an independent contractor or agent. The Director's notice of intent will afford the permittee(s) or lessee(s) a period of not less than 5 working days within which to comment on the intended action. When the Director so notifies a lessee or permittee of the intent to disclose data or information to an independent contractor or agent, all other owners of such data or information shall be deemed to have been notified of the Director's intent. Prior to any such disclosure, the contractor or agent shall be required to execute a written commitment not to disclose any data or information to anyone without the express consent of the Director, and not to make any disclosure or use of the data or information other than that provided in the contract. Contracts between the Minerals Management Service and independent contractors shall be available to the lessee(s) or permittee(s) for inspection. In the event of any unauthorized use or disclosure of data or information by the contractor or agent, or by an employee thereof, the responsible contractor or agent or employee thereof shall be liable for penalties pursuant to section 24 of the Act.
(e)(1) After delivery of data or information in accordance with paragraph (b)(1) of this section and upon receipt of a request for reimbursement and a determination by the Director that the requested reimbursement is proper, the lessee or permittee shall be reimbursed for the cost of reproducing the data or information at the lessee's or permittee's lowest rate or at the lowest commercial rate established in the area, whichever is less. Requests for reimbursement must be made within 60 days of the delivery date of the data or information requested under paragraph (b)(1) of this section.
(2) After delivery of data or information in accordance with paragraph (b)(3) of this section, and upon receipt of a request for reimbursement and a determination by the Director that the requested reimbursement is proper, the lessee or permittee shall be reimbursed for the cost of processing or reprocessing and of reproducing the requested data or information. Requests for reimbursement must be made within 60 days of the delivery date of the data or information and shall be for only the costs attributable to processing or reprocessing and reproducing, as distinguished from the costs of data acquisition.
(3) Requests for reimbursement are to contain a breakdown of costs in sufficient detail to allow separation of reproduction, processing, and reprocessing costs from acquisition and other costs.
(f) Each Federal Department or Agency shall provide the Director with any data which it has obtained pursuant to section 11 of the Act and any other information which may be necessary or useful to assist the Director in carrying out the provisions of the Act.
[44 FR 46408, Aug. 7, 1979, as amended at 51 FR 17176, May 9, 1986]
§ 252.4
Summary Report to affected States.
(a) The Director, as soon as practicable after analysis, interpretation, and compilation of oil and gas data and information developed by the Minerals Management Service or furnished by lessees, permittees, or other government agencies, shall make available to affected States and, upon request, to the executive of any affected local government, a Summary Report of data and information designed to assist them in planning for the onshore impacts of potential OCS oil and gas development and production. The Director shall consult with affected States and other interested parties to define the nature, scope, content, and timing of the Summary Report. The Director may consult with affected States and other interested parties regarding subsequent revisions in the definition of the nature, scope, content, and timing of the Summary Report. The Summary Report shall not contain data or information which the Director determines is exempt from disclosure in accordance with this part. The Summary Report shall not contain data or information the release of which the Director determines would unduly damage the competitive position of the lessee or permittee who provided the data or information which the Director has processed, analyzed, or interpreted during the development of the Summary Report. The Summary Report shall include:
(1) Estimates of oil and gas reserves; estimates of the oil and gas resources that may be found within areas which the Secretary has leased or plans to offer for lease; and when available, projected rates and volumes of oil and gas to be produced from leased areas;
(2) Magnitude of the approximate projections and timing of development, if and when oil or gas, or both, is discovered;
(3) Methods of transportation to be used, including vessels and pipelines and approximate location of routes to be followed; and
(4) General location and nature of near-shore and onshore facilities expected to be utilized.
(b) When the Director determines that significant changes have occurred in the information contained in a Summary Report, the Director shall prepare and make available the new or revised information to each affected State, and, upon request, to the executive of any affected local government.
§ 252.5
Information to be made available to affected States.
(a) The Director shall prepare an index of OCS information (see 30 CFR 256.10). The index shall list all relevant actual or proposed programs, plans, reports, environmental impact statements, nominations information, environmental study reports, lease sale information, and any similar type of relevant information, including modifications, comments, and revisions prepared or directly obtained by the Director under the Act. The index shall be sent to affected States and, upon request, to any affected local government. The public shall be informed of the availability of the index.
(b) Upon request, the Director shall transmit to affected States, affected local governments, and the public a copy of any information listed in the index which is subject to the control of the Minerals Management Service, in accordance with the requirements and subject to the limitations of the Freedom of Information Act (5 U.S.C. 552) and implementing regulations. The Director shall not transmit or make available any information which he determines is exempt from disclosure in accordance with this part.
[44 FR 46408, Aug. 7, 1979, as amended at 54 FR 50617, Dec. 8, 1989]
§ 252.6
Freedom of Information Act requirements.
(a) The Director shall make data and information available in accordance with the requirements and subject to the limitations of the Freedom of Information Act (5 U.S.C. 552), the regulations contained in 43 CFR part 2 (Records and Testimony), the requirements of the Act, and the regulations contained in 30 CFR part 250 (Oil and Gas and Sulphur Operations in the Outer Continental Shelf) and 30 CFR part 251 (Geological and Geophysical Explorations of the Outer Continental Shelf).
(b) Except as provided in § 252.7 or in parts 250 and 251 of this chapter, no data or information determined by the director to be exempt from public disclosure under paragraph (a) of this section shall be provided to any affected State or be made available to the executive of any affected local government or to the public unless the lessee, or the permittee and all persons to whom such permittee has sold such data or information under promise of confidentiality, agree to such action.
§ 252.7
Privileged and proprietary data and information to be made available to affected States.
(a)(1) The Governor of any affected State may designate an appropriate State official to inspect, at a regional location which the Director shall designate, any privileged or proprietary data or information received by the Director regarding any activity in an area adjacent to such State, except that no such inspection shall take place prior to the sale of a lease covering the area in which such activity was conducted.
(2)(i) Except as provided for in 30 CFR 250.106 and 251.14, no privileged or proprietary data or information will be transmitted to any affected State unless the lessee who provided the privileged or proprietary data or information agrees in writing to the transmittal of the data or information.
(ii) Except as provided for in 30 CFR 250.106 and 251.14, no privileged or proprietary data or information will be transmitted to any affected State unless the permittee and all persons to whom the permittee has sold the data or information under promise of confidentiality agree in writing to the transmittal of the data or information.
(3) Knowledge obtained by a State official who inspects data or information under paragraph (a)(1) or who receives data or information under paragraph (a)(2) of this section shall be subject to the requirements and limitations of the Freedom of Information Act (5 U.S.C. 552), the regulations contained in 43 CFR part 2 (Records and Testimony), the Act (92 Stat. 629), the regulations contained in 30 CFR part 250 (Oil and Gas and Sulphur Operations in the Outer Continental Shelf), the regulations contained in 30 CFR part 251 (Geological and Geophysical Explorations of the Outer Continental Shelf), and the regulations contained in this part 252 (Outer Continental Shelf Oil and Gas Information Program).
(4) Prior to the transmittal of any privileged or proprietary data or information to any State, or the grant of access to a State official to such data or information, the Secretary shall enter into a written agreement with the Governor of the State in accordance with section 26(e) of the Act (43 U.S.C. 1352). In that agreement the State shall agree, as a condition precedent to receiving or being granted access to such data or information to: (i) Protect and maintain the confidentiality of privileged or proprietary data and information in accordance with the laws and regulations listed in paragraph (a)(3) of this section; (ii) waive the defenses as set forth in paragraph (b)(2) of this section; and (iii) hold the United States harmless from any violations of the agreement to protect the confidentiality of privileged or proprietary data or information by the State or its employees or contractors.
(b)(1) Whenever any employee of the Federal Government or of any State reveals in violation of the Act or of the provisions of the regulations implementing the Act, privileged or proprietary data or information obtained pursuant to the regulations in this chapter, the lessee or permittee who supplied such information to the Director or any other Federal official, and any person to whom such lessee or permittee has sold such data or information under the promise of confidentiality, may commence a civil action for damages in the appropriate district court of the United States against the Federal Government or such State, as the case may be. Any Federal or State employee who is found guilty of failure to comply with any of the requirements of this section shall be subject to the penalties described in section 24 of the Act (43 U.S.C. 1350).
(2) In any action commenced against the Federal Government or a State pursuant to paragraph (b)(1) of this section, the Federal Government or such State, as the case may be, may not raise as a defense any claim of sovereign immunity, or any claim that the employee who revealed the privileged or proprietary data or information which is the basis of such suit was acting outside the scope of the person's employment in revealing such data or information.
(c) If the Director finds that any State cannot or does not comply with the conditions described in the agreement entered into pursuant to paragraph (a)(4) of this section, the Director shall thereafter withhold transmittal and deny access for inspection of privileged or proprietary data or information to such State until the Director finds that such State can and will comply with those conditions.
[44 FR 46408, Aug. 7, 1979, as amended at 64 FR 72794, Dec. 28, 1999]
Pt. 253

PART 253—OIL SPILL FINANCIAL RESPONSIBILITY FOR OFFSHORE FACILITIES

Subpart A—General
Sec.
253.1
What is the purpose of this part?
253.3
How are the terms used in this regulation defined?
253.5
What is the authority for collecting Oil Spill Financial Responsibility (OSFR) information?

Subpart B—Applicability and Amount of OSFR
253.10
What facilities does this part cover?
253.11
Who must demonstrate OSFR?
253.12
May I ask MMS for a determination of whether I must demonstrate OSFR?
253.13
How much OSFR must I demonstrate?
253.14
How do I determine the worst case oil-spill discharge volume?
253.15
What are my general OSFR compliance responsibilities?

Subpart C—Methods for Demonstrating OSFR
253.20
What methods may I use to demonstrate OSFR?
253.21
How can I use self-insurance as OSFR evidence?
253.22
How do I apply to use self-insurance as OSFR evidence?
253.23
What information must I submit to support my net worth demonstration?
253.24
When I submit audited annual financial statements to verify my net worth, what standards must they meet?
253.25
What financial test procedures must I use to determine the amount of self-insurance allowed as OSFR evidence based on net worth?
253.26
What information must I submit to support my unencumbered net assets demonstration?
253.27
When I submit audited annual financial statements to verify my unencumbered assets, what standards must they meet?
253.28
What financial test procedures must I use to evaluate the amount of self-insurance allowed as OSFR evidence based on unencumbered assets?
253.29
How can I use insurance as OSFR evidence?
253.30
How can I use an indemnity as OSFR evidence?
253.31
How can I use a surety bond as OSFR evidence?
253.32
Are there alternative methods to demonstrate OSFR?

Subpart D—Requirements for Submitting OSFR Information
253.40
What OSFR evidence must I submit to MMS?
253.41
What terms must I include in my OSFR evidence?
253.42
How can I amend my list of COFs?
253.43
When is my OSFR demonstration or the amendment to my OSFR demonstration effective?
253.44
When must I comply with this subpart?
253.45
Where do I send my OSFR evidence?

Subpart E—Revocation and Penalties
253.50
How can MMS refuse or invalidate my OSFR evidence?
253.51
What are the penalties for not complying with this part?

Subpart F—Claims for Oil-Spill Removal Costs and Damages
253.60
To whom may I present a claim?
253.61
When is a guarantor subject to direct action for claims?
253.62
What are the designated applicant's notification obligations regarding a claim?
Appendix to Part 253—List of U.S. Geological Survey Topographic Maps

Authority:
33 U.S.C. 2701 et seq., 28 U.S.C. 2461 (note)

Source:
63 FR 42711, Aug. 11, 1998, unless otherwise noted.

Effective Date Note:
At 63 FR 42711, Aug. 11, 1998, part 253 was added. This part contains information collection and recordkeeping requirements and will not become effective until approval has been given by the Office of Management and Budget.

Subpart A—General
§ 253.1
What is the purpose of this part?
This part establishes the requirements for demonstrating OSFR for covered offshore facilities (COFs) under Title I of the Oil Pollution Act of 1990 (OPA), as amended, 33 U.S.C. 2701 et seq.
§ 253.3
How are the terms used in this regulation defined?
Terms used in this part have the following meaning:
Advertise means publication of the notice of designation of the source of the incident and the procedures by which the claims may be presented, according to 33 CFR part 136, subpart D.
Bay means a body of water included in the Geographic Names Information System (GNIS) bay feature class. A GNIS bay includes an arm, bay, bight, cove, estuary, gulf, inlet, or sound.
Claim means a written request, for a specific sum, for compensation for damages or removal costs resulting from an oil-spill discharge or a substantial threat of the discharge of oil.
Claimant means any person or government who presents a claim for compensation under OPA.
Coastline means the line of ordinary low water along that portion of the coast that is in direct contact with the open sea which marks the seaward limit of inland waters.
Covered offshore facility (COF) means a facility:
(1) That includes any structure and all its components (including wells completed at the structure and the associated pipelines), equipment, pipeline, or device (other than a vessel or other than a pipeline or deepwater port licensed under the Deepwater Port Act of 1974 (33 U.S.C. 1501 et seq.)) used for exploring for, drilling for, or producing oil or for transporting oil from such facilities. This includes a well drilled from a mobile offshore drilling unit (MODU) and the associated riser and well control equipment from the moment a drill shaft or other device first touches the seabed for purposes of exploring for, drilling for, or producing oil, but it does not include the MODU; and
(2) That is located:
(i) Seaward of the coastline; or
(ii) In any portion of a bay that is:
(A) Connected to the sea, either directly or through one or more other bays; and
(B) Depicted in whole or in part on any USGS map listed in the Appendix to this part, or on any map published by the USGS that is a successor to and covers all or part of the same area as a listed map. Where any portion of a bay is included on a listed map, this rule applies to the entire bay; and
(3) That has a worst case oil-spill discharge potential of more than 1,000 bbls of oil, or a lesser volume if the Director determines in writing that the oil-spill discharge risk justifies the requirement to demonstrate OSFR.
Designated applicant means a person the responsible parties designate to demonstrate OSFR for a COF on a lease, permit, or right-of-use and easement.
Director means the Director of the Minerals Management Service.
Fund means the Oil Spill Liability Trust Fund established by section 9509 of the Internal Revenue Code of 1986 as amended (26 U.S.C. 9509).
Geographic Names Information System (GNIS) means the database developed by the USGS in cooperation with the U.S. Board of Geographic Names which contains the federally-recognized geographic names for all known places, features, and areas in the United States that are identified by a proper name. Each feature is located by state, county, and geographic coordinates and is referenced to the appropriate 1:24,000-scale or 1:63,360-scale USGS topographic map on which it is shown.
Guarantor means a person other than a responsible party who provides OSFR evidence for a designated applicant.
Guaranty means any acceptable form of OSFR evidence provided by a guarantor including an indemnity, insurance, or surety bond.
Incident means any occurrence or series of occurrences having the same origin that results in the discharge or substantial threat of the discharge of oil.
Indemnity means an agreement to indemnify a designated applicant upon its satisfaction of a claim.
Indemnitor means a person providing an indemnity for a designated applicant.
Independent accountant means a certified public accountant who is certified by a state, or a chartered accountant certified by the government of jurisdiction within the country of incorporation of the company proposing to use one of the self-insurance evidence methods specified in this subpart.
Insolvent has the meaning set forth in 11 U.S.C. 101, and generally refers to a financial condition in which the sum of a person's debts is greater than the value of the person's assets.
Lease means any form of authorization issued under the Outer Continental Shelf Lands Act or state law which allows oil and gas exploration and production in the area covered by the authorization.
Lessee means a person holding a leasehold interest in an oil or gas lease including an owner of record title or a holder of operating rights (working interest owner).
Oil means oil of any kind or in any form, except as excluded by paragraph (2) of this definition.
(1) Oil includes:
(i) Petroleum, fuel oil, sludge, oil refuse, and oil mixed with wastes other than dredged spoil;
(ii) Hydrocarbons produced at the wellhead in liquid form;
(iii) Gas condensate that has been separated from gas before pipeline injection.
(2) Oil does not include petroleum, including crude oil or any fraction thereof, which is specifically listed or designated as a hazardous substance under subparagraphs (A) through (F) of section 101(14) of the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) (42 U.S.C. 9601).
Oil Spill Financial Responsibility (OSFR) means the capability and means by which a responsible party for a covered offshore facility will meet removal costs and damages for which it is liable under Title I of the Oil Pollution Act of 1990, as amended (33 CFR 2701 et seq.), with respect to both oil-spill discharges and substantial threats of the discharge of oil.
Outer Continental Shelf (OCS) has the same meaning as the term “Outer Continental Shelf” defined in section 2(a) of the OCS Lands Act (OCSLA) (43 U.S.C. 1331(a)).
Permit means an authorization, license, or permit for geological exploration issued under section 11 of the OCSLA (43 U.S.C. 1340) or applicable state law.
Person means an individual, corporation, partnership, association (including a trust or limited liability company), state, municipality, commission or political subdivision of a state, or any interstate body.
Pipeline means the pipeline segments and any associated equipment or appurtenances used or intended for use in the transportation of oil or natural gas.
Responsible party has the following meanings:
(1) For a COF that is a pipeline, responsible party means any person owning or operating the pipeline;
(2) For a COF that is not a pipeline, responsible party means either the lessee or permittee of the area in which the COF is located, or the holder of a right-of-use and easement granted under applicable state law or the OCSLA (43 U.S.C. 1301-1356) for the area in which the COF is located (if the holder is a different person than the lessee or permittee). A Federal agency, State, municipality, commission, or political subdivision of a state, or any interstate body that as owner transfers possession and right to use the property to another person by lease, assignment, or permit is not a responsible party; and
(3) For an abandoned COF, responsible party means any person who would have been a responsible party for the COF immediately before abandonment.
Right-of-use and easement (RUE) means any authorization to use the OCS or submerged land for purposes other than those authorized by a lease or permit, as defined herein. It includes pipeline rights-of-way.
Source of the incident means the facility from which oil was discharged or which poses a substantial threat of discharging oil, as designated by the Director, National Pollution Funds Center, according to 33 CFR part 136, subpart D.
State means the several States of the United States, the District of Columbia, the Commonwealth of Puerto Rico, Guam, American Samoa, the United States Virgin Islands, the Commonwealth of the Northern Marianas, and any other territory or possession of the United States.
§ 253.5
What is the authority for collecting Oil Spill Financial Responsibility (OSFR) information?
(a) The Office of Management and Budget (OMB) has approved the information collection requirements in this part 253 under 44 U.S.C. 3501 et seq. and assigned OMB control number 1010-0106.
(b) MMS collects the information to ensure that the designated applicant for a COF has the financial resources necessary to pay for cleanup and damages that could be caused by oil discharges from the COF. MMS uses the information to ensure compliance of offshore lessees, owners, and operators of covered facilities with OPA; to establish eligibility of designated applicants for OSFR certification (OSFRC); and to establish a reference source of names, addresses, and telephone numbers of responsible parties for covered facilities and their designated agents, guarantors, and U.S. agents for service of process for claims associated with oil pollution from designated covered facilities. The requirement to provide the information is mandatory. No information submitted for OSFRC is confidential or proprietary.
(c) An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number.
(d) Send comments regarding any aspect of the collection of information under this part, including suggestions for reducing the burden, to the Information Collection Clearance Officer, Minerals Management Service, Mail Stop 4230, 1849 C Street, NW., Washington, DC 20240.
[63 FR 42711, Aug. 11, 1998, as amended at 65 FR 2876, Jan. 19, 2000]

Subpart B—Applicability and Amount of OSFR
§ 253.10
What facilities does this part cover?
(a) This part applies to any COF on any lease or permit issued or on any RUE granted under the OCSLA or applicable state law.
(b) For a pipeline COF that extends onto land, this part applies to that portion of the pipeline lying seaward of the first accessible flow shut-off device on land.
§ 253.11
Who must demonstrate OSFR?
(a) A designated applicant must demonstrate OSFR. A designated applicant may be a responsible party or another person authorized under this section. Each COF must have a single designated applicant.
(1) If there is more than one responsible party, those responsible parties must use Form MMS-1017 to select a designated applicant. The designated applicant must submit Form MMS-1016 and agree to demonstrate OSFR on behalf of all the responsible parties.
(2) If you are a designated applicant who is not a responsible party, you must agree to be liable for claims made under OPA jointly and severally with the responsible parties.
(b) The designated applicant for a COF on a lease must be either:
(1) A lessee; or
(2) The designated operator for the OCS lease under 30 CFR 250.143 or the unit operator designated under a Federally approved unit including the OCS lease. For a lease or unit not in the OCS, the operator designated under the lease or unit operating agreement for the lease may be the designated applicant only if the operator has agreed to be responsible for compliance with all the laws and regulations applicable to the lease or unit.
(c) The designated applicant for a COF on a permit must be the permittee.
(d) The designated applicant for a COF on a RUE must be the holder of the RUE or, if there is a pipeline on the RUE, the owner or operator of the pipeline.
(e) MMS may require the designated applicant for a lease, permit, or RUE to be a person other than a person identified in paragraphs (b) through (d) of this section if MMS determines that a person identified in paragraphs (b) through (d) cannot adequately demonstrate OSFR.
(f) If you are a responsible party and you fail to designate an applicant, then you must demonstrate OSFR under the requirements of this part.
[63 FR 42711, Aug. 11, 1998, as amended at 64 FR 72794, Dec. 28, 1999]
§ 253.12
May I ask MMS for a determination of whether I must demonstrate OSFR?
You may submit to MMS a request for a determination of OSFR applicability. Address the request to the office identified in § 253.45. You must include in your request any information that will assist MMS in making the determination. MMS may require you to submit other information before making a determination of OSFR applicability.
§ 253.13
How much OSFR must I demonstrate?
(a) The following general parameters apply to the amount of OSFR that you must demonstrate:
If you are the designated applicant for | Then you must demonstrate
Only one COF | The amount of OSFR that applies to the COF.
More than one COF | The highest amount of OSFR that applies to any one of the COFs.
(b) You must demonstrate OSFR in the amounts specified in this section:
(1) For a COF located wholly or partially in the OCS you must demonstrate OSFR in accordance with the following table:
COF worst case oil-spill discharge volume | Applicable amount of OSFR
Over 1,000 bbls but not more than 35,000 bbls | $35,000,000
Over 35,000 but not more than 70,000 bbls | 70,000,000
Over 70,000 but not more than 105,000 bbls | 105,000,000
Over 105,000 bbls | 150,000,000
(2) For a COF not located in the OCS you must demonstrate OSFR in accordance with the following table:
COF worst case oil-spill discharge volume | Applicable amount of OSFR
Over 1,000 bbls but not more than 10,000 bbls | $10,000,000
Over 10,000 but not more than 35,000 bbls | 35,000,000
Over 35,000 but not more than 70,000 bbls | 70,000,000
Over 70,000 but not more than 105,000 bbls | 105,000,000
Over 105,000 bbls | 150,000,000
(3) The Director may determine that you must demonstrate an amount of OSFR greater than the amount in paragraphs (b)(1) and (2) of this section based on the relative operational, environmental, human health, and other risks that your COF poses. The Director may require an amount that is one or more levels higher than the amount indicated in paragraph (b)(1) or (2) of this section for your COF. The Director will not require an OSFR demonstration that exceeds $150 million.
(4) You must demonstrate OSFR in the lowest amount specified in the applicable table in paragraph (b)(1) or (b)(2) for a facility with a potential worst case oil-spill discharge of 1,000 bbls or less if the Director notifies you in writing that the demonstration is justified by the risks of the potential oil-spill discharge.
§ 253.14
How do I determine the worst case oil-spill discharge volume?
(a) To calculate the amount of OSFR you must demonstrate for a facility under § 253.13(b), you must use the worst case oil-spill discharge volume that you determined under whichever of the following regulations applies:
(1) 30 CFR Part 254—Response Plans for Facilities Located Seaward of the Coast Line, except that the volume of the worst case oil-spill discharge for a well must be four times the uncontrolled flow volume that you estimate for the first 24 hours.
(2) 40 CFR Part 112—Oil Pollution Prevention; or
(3) 49 CFR Part 194—Response Plans for Onshore Oil Pipelines.
(b) If you are a designated applicant and you choose to demonstrate $150 million in OSFR, you are not required to determine any worst case oil-spill discharge volumes, since that is the maximum amount of OSFR required under this part.
§ 253.15
What are my general OSFR compliance responsibilities?
(a) You must maintain continuous OSFR coverage for all your leases, permits, and RUEs with COFs for which you are the designated applicant.
(b) You must ensure that new OSFR evidence is submitted before your current evidence lapses or is canceled and that coverage for your new COF is submitted before the COF goes into operation.
(c) If you use self-insurance to demonstrate OSFR and find that you no longer qualify to self-insure the required OSFR amount based upon your latest audited annual financial statements, then you must demonstrate OSFR using other methods acceptable to MMS by whichever of the following dates comes first:
(1) Sixty calendar days after you receive your latest audited annual financial statement; or
(2) The first calendar day of the 5th month after the close of your fiscal year.
(d) You may use a surety bond to demonstrate OSFR. If you find that your bonding company has lost its state license or has had its U.S. Treasury Department certification revoked, then you must replace the surety bond within 15 calendar days using a method of OSFR that is acceptable to MMS.
(e) You must notify MMS in writing within 15 calendar days after a change occurs that would prevent you from meeting your OSFR obligations (e.g., if you or your indemnitor petition for bankruptcy under Chapters 7 or 11 of Title 11, U.S.C.). You must take any action MMS directs to ensure an acceptable OSFR demonstration.
(f) If you deny payment of a claim presented to you under § 253.60, then you must give the claimant a written explanation for your denial.
[63 FR 42711, Aug. 11, 1998; 63 FR 48578, Sept. 11, 1998]

Subpart C—Methods for Demonstrating OSFR
§ 253.20
What methods may I use to demonstrate OSFR?
As the designated applicant, you may satisfy your OSFR requirements by using one or a combination of the following methods to demonstrate OSFR:
(a) Self-insurance under §§ 253.21 through 253.28;
(b) Insurance under § 253.29;
(c) An indemnity under § 253.30;
(d) A surety bond under § 253.31; or
(e) An alternative method the Director approves under § 253.32.
§ 253.21
How can I use self-insurance as OSFR evidence?
(a) If you use self-insurance to satisfy all or part of your obligation to demonstrate OSFR, you must annually pass either a net worth test under § 253.25 or an unencumbered net asset test under § 253.28.
(b) To establish the amount of self-insurance allowed, you must submit evidence of your net worth under § 253.23 or evidence of your unencumbered assets under § 253.26.
(c) You must identify a U.S. agent for service of process.
§ 253.22
How do I apply to use self-insurance as OSFR evidence?
(a) You must submit a complete Form MMS-1018 with each application to demonstrate OSFR using self-insurance.
(b) You must submit your application to renew OSFR using self-insurance by the first calendar day of the 5th month after the close of your fiscal year. You may submit to MMS your initial application to demonstrate OSFR using self-insurance at any time.
§ 253.23
What information must I submit to support my net worth demonstration?
You must support your net worth evaluation with information contained in your previous fiscal year's audited annual financial statement.
(a) Audited annual financial statements must be in the form of:
(1) An annual report, prepared in accordance with the generally accepted accounting practices (GAAP) of the United States or other international accounting practices determined to be equivalent by MMS; or
(2) A Form 10-K or Form 20-F, prepared in accordance with Securities and Exchange Commission regulations.
(b) Audited annual financial statements must be submitted together with a letter signed by your treasurer highlighting:
(1) The State or the country of incorporation;
(2) The total amount of the stockholders' equity as shown on the balance sheet;
(3) The net amount of the plant, property, and equipment shown on the balance sheet; and
(4) The net amount of the identifiable U.S. assets and the identifiable total assets in the auditor's notes to the financial statement (i.e., a geographic segmented business note).
§ 253.24
When I submit audited annual financial statements to verify my net worth, what standards must they meet?
(a) Your audited annual financial statements must be bound.
(b) Your audited annual financial statements must include the unqualified opinion of an independent accountant that states:
(1) The financial statements are free from material misstatement, and
(2) The audit was conducted in accordance with the generally accepted auditing standards (GAAS) of the United States, or other international auditing standards that MMS determines to be equivalent.
(c) The financial information you submit must be expressed in U.S. dollars. If this information was originally reported in another form of currency, you must convert it to U.S. dollars using the conversion factor that was effective on the last day of the fiscal year pertinent to your financial statements. You also must identify the source of the currency exchange rate.
§ 253.25
What financial test procedures must I use to determine the amount of self-insurance allowed as OSFR evidence based on net worth?
(a) Divide the total amount of the stockholders'/owners' equity listed on the balance sheet by ten.
(b) Divide the net amount of the identifiable U.S. assets by the net amount of the identifiable total assets.
(c) Multiply the net amount of plant, property, and equipment shown on the balance sheet by the number calculated under paragraph (b) of this section and divide the resultant product by ten.
(d) The smaller of the numbers calculated under paragraphs (a) or (c) of this section is the maximum allowable amount you may use to demonstrate OSFR under this method.
§ 253.26
What information must I submit to support my unencumbered assets demonstration?
You must support your unencumbered assets evaluation with the information required by § 253.23(a) and a list of reserved, unencumbered, and unimpaired U.S. assets whose value will not be affected by an oil discharge from a COF. The assets must be plant, property, or equipment held for use. You must submit a letter signed by your treasurer:
(a) Identifying which assets are reserved;
(b) Certifying that the assets are unencumbered, including contingent encumbrances;
(c) Promising that the identified assets will not be sold, subjected to a security interest, or otherwise encumbered throughout the specified fiscal year; and
(d) Specifying:
(1) The State or the country of incorporation;
(2) The total amount of the stockholders'/owners' equity listed on the balance sheet;
(3) The identification and location of the reserved U.S. assets; and
(4) The value of the reserved U.S. assets less accumulated depreciation and amortization, using the same valuation method used in your audited annual financial statement and expressed in U.S. dollars. The net value of the reserved assets must be at least two times the self-insurance amount requested for demonstration.
§ 253.27
When I submit audited annual financial statements to verify my unencumbered assets, what standards must they meet?
Any audited annual financial statements that you submit must:
(a) Meet the standards in § 253.24; and
(b) Include a certification by the independent accountant who audited the financial statements that states:
(1) The value of the unencumbered assets is reasonable and uses the same valuation method used in your audited annual financial statements;
(2) Any existing encumbrances are noted;
(3) The assets are long-term assets held for use; and
(4) The valuation method used in the audited annual financial statements is for long-term assets held for use.
§ 253.28
What financial test procedures must I use to evaluate the amount of self-insurance allowed as OSFR evidence based on unencumbered assets?
(a) Divide the total amount of the stockholders'/owners' equity listed on the balance sheet by 4.
(b) Divide the value of the unencumbered U.S. assets by 2.
(c) The smaller number calculated under paragraphs (a) or (b) of this section is the maximum allowable amount you may use to demonstrate OSFR under this method.
§ 253.29
How can I use insurance as OSFR evidence?
(a) If you use insurance to satisfy all or part of your obligation to demonstrate OSFR, you may use only insurance certificates issued by insurers that have achieved a “Secure” rating for claims paying ability in their latest review by A.M. Best's Insurance Reports, Standard & Poor's Insurance Rating Services, or other equivalent rating made by a rating service acceptable to MMS.
(b) You must submit information about your insurers to MMS on a completed and unaltered Form MMS-1019. The information you submit must:
(1) Include all the information required by § 253.41 and
(2) Be executed on one original insurance certificate (i.e., Form MMS-1019) for each OSFR layer (see paragraph (c) of this section ), showing all participating insurers and their proportion (quota share) of this risk. The certificate must bear the original signatures of each insurer's underwriter or of their lead underwriters, underwriting managers, or delegated brokers, depending on who is authorized to bind the underwriter.
(3) For each insurance company on the insurance certificate, indicate the insurer's claims-paying-ability rating and the rating service that issued the rating.
(c) The insurance evidence you provide to MMS as OSFR evidence may be divided into layers, subject to the following restrictions:
(1) The total amount of OSFR evidence must equal the total amount you must demonstrate under § 253.13;
(2) No more than one insurance certificate may be used to cover each OSFR layer specified in § 253.13(b) (i.e., four layers for an OCS COF, and five layers for a non-OCS COF);
(3) You may use one insurance certificate to cover any number of consecutive OSFR layers;
(4) Each insurer's participation in the covered insurance risk must be on a proportional (quota share) basis, must be expressed as a percentage of a whole layer, and the certificate must not contain intermediate, horizontal layers;
(5) You may use an insurance deductible. If you use more than one insurance certificate, the deductible amount must apply only to the certificate that covers the base OSFR amount layer. To satisfy an insurance deductible, you may use only those methods that are acceptable as evidence of OSFR under this part; and
(6) You must identify a U.S. agent for service of process on each insurance certificate you submit to MMS. The agent may be different for each insurance certificate.
(d) You may submit to MMS a temporary insurance confirmation (fax binder) for each insurance certificate you use as OSFR evidence. Submit your fax binder on Form MMS-1019, and each form must include the signature of an underwriter for at least one of the participating insurers. MMS will accept your fax binder as OSFR evidence during a period that ends 90 days after the date that you need the insurance to demonstrate OSFR.
§ 253.30
How can I use an indemnity as OSFR evidence?
(a) You may use only one indemnity issued by only one indemnitor to satisfy all or part of your obligation to demonstrate OSFR.
(b) Your indemnitor must be your corporate parent or affiliate.
(c) Your indemnitor must complete a Form MMS-1018 and provide an indemnity that:
(1) Includes all the information required by § 253.41; and
(2) Does not exceed the amounts calculated using the net worth or unencumbered assets tests specified under §§ 253.21 through 253.28.
(d) You must submit your application to renew OSFR using an indemnity by the first calendar day of the 5th month after the close of your indemnitor's fiscal year. You may submit to MMS your initial application to demonstrate OSFR using an indemnity at any time.
(e) Your indemnitor must identify a U.S. agent for service of process.
§ 253.31
How can I use a surety bond as OSFR evidence?
(a) Each bonding company that issues a surety bond that you submit to MMS as OSFR evidence must:
(1) Be licensed to do business in the State in which the surety bond is executed;
(2) Be certified by the U.S. Treasury Department as an acceptable surety for Federal obligations and listed in the current Treasury Circular No. 570;
(3) Provide the surety bond on Form MMS-1020; and
(4) Be in compliance with applicable statutes regulating surety company participation in insurance-type risks.
(b) A surety bond that you submit as OSFR evidence must include all the information required by § 253.41.
§ 253.32
Are there alternative methods to demonstrate OSFR?
The Director may accept other methods to demonstrate OSFR that provide equivalent assurance of timely satisfaction of claims. This may include pooling, letters of credit, pledges of treasury notes, or other comparable methods. Submit your proposal, together with all the supporting documents, to the Director at the address listed in § 253.45. The Director's decision whether to approve your alternative method to evidence OSFR is by this rule committed to the Director's sole discretion and is not subject to administrative appeal under 30 CFR part 290 or 43 CFR part 4.

Subpart D—Requirements for Submitting OSFR Information
§ 253.40
What OSFR evidence must I submit to MMS?
(a) You must submit to MMS:
(1) A single demonstration of OSFR that covers all the COFs for which you are the designated applicant;
(2) A completed and unaltered Form MMS-1016;
(3) MMS forms that identify your COFs (Form MMS-1021, Form MMS-1022), and the methods you will use to demonstrate OSFR (Form MMS-1018, Form MMS-1019, Form MMS-1020). Forms are available from the address listed in § 253.45;
(4) Any insurance certificates, indemnities, and surety bonds used as OSFR evidence for the COFs for which you are the designated applicant;
(5) A completed Form MMS-1017 for each responsible party, unless you are the only responsible party for the COFs covered by your OSFR demonstration; and
(6) Other financial instruments and information the Director requires to support your OSFR demonstration under § 253.32.
(b) Each MMS form you submit to MMS as part of your OSFR demonstration must be signed. You also must attach to Form MMS-1016 proof of your authority to sign.
§ 253.41
What terms must I include in my OSFR evidence?
(a) Each instrument you submit as OSFR evidence must specify:
(1) The effective date, and except for a surety bond, the expiration date;
(2) That termination of the instrument will not affect the liability of the instrument issuer for claims arising from an incident (i.e., oil-spill discharge or substantial threat of the discharge of oil) that occurred on or before the effective date of termination;
(3) That the instrument will remain in force until the termination date or until the earlier of:
(i) Thirty calendar days after MMS and the designated applicant receive from the instrument issuer a notification of intent to cancel; or
(ii) MMS receives from the designated applicant other acceptable OSFR evidence; or
(iii) All the COFs to which the instrument applies are permanently abandoned in compliance with 30 CFR part 250 or equivalent State requirements;
(4) That the instrument issuer agrees to direct action for claims made under OPA up to the guaranty amount, subject to the defenses in paragraph (a)(6) of this section and following the procedures in § 253.60 of this part;
(5) An agent in the United States for service of process; and
(6) That the instrument issuer will not use any defenses against a claim made under OPA except:
(i) The rights and defenses that would be available to a designated applicant or responsible party for whom the guaranty was provided; and
(ii) The incident (i.e., oil-spill discharge or a substantial threat of the discharge of oil) leading to the claim for removal costs or damages was caused by willful misconduct of a responsible party for whom the designated applicant demonstrated OSFR.
(b) You may not change, omit, or add limitations or exceptions to the terms and conditions in an MMS form that you submit as part of your OSFR demonstration. If you attempt to do this, MMS will disregard the changes, omissions, additions, limitations, or exceptions and by operation of this rule MMS will consider the form to contain all the terms and conditions included on the original MMS form.
§ 253.42
How can I amend my list of COFs?
(a) If you want to add a COF that is not identified in your current OSFR demonstration, you must submit to MMS a completed Form MMS-1022. If applicable, you also must submit any additional indemnities, surety bonds, insurance certificates, or other instruments required to extend the coverage of your original OSFR demonstration to the COFs to be added. You do not need to resubmit previously accepted audited annual financial statements for the current fiscal year.
(b) If you want to drop a COF identified in your current OSFR demonstration, you must submit to MMS a completed Form MMS-1022. You must continue to demonstrate OSFR for the COF until MMS approves OSFR evidence for the COF from another designated applicant, or OSFR is no longer required (e.g., until a well that is a COF is properly plugged and abandoned).
§ 253.43
When is my OSFR demonstration or the amendment to my OSFR demonstration effective?
(a) MMS will notify you in writing when we approve your OSFR demonstration. If we find that you have not submitted all the information needed to demonstrate OSFR, we may require you to provide additional information before we determine whether your OSFR evidence is acceptable.
(b) Except in the case of self-insurance or an indemnity, MMS acceptance of OSFR evidence is valid until the surety bond, insurance certificate, or other accepted OSFR instrument expires or is canceled. In the case of self-insurance or indemnity, acceptance is valid until the first day of the 5th month after the close of your or your indemnitor's current fiscal year.
§ 253.44
When must I comply with this part?
If you are the designated applicant for one or more COFs covered by a Certificate of Financial Responsibility (CFR) issued under 33 CFR part 135 that expires after October 13, 1998, you must submit to MMS your evidence of OSFR for all your COFs no later than the earliest date that an existing CFR for any of your COFs expires. All other designated applicants must submit to MMS evidence of OSFR for their COFs no later than April 8, 1999.
§ 253.45
Where do I send my OSFR evidence?
Address all correspondence and required submissions related to this part to: U.S. Department of the Interior, Minerals Management Service, Gulf of Mexico Region, Oil Spill Financial Responsibility Program, 1201 Elmwood Park Boulevard, New Orleans, Louisiana 70123.

Subpart E—Revocation and Penalties
§ 253.50
How can MMS refuse or invalidate my OSFR evidence?
(a) If MMS determines that any OSFR evidence you submit fails to comply with the requirements of this part, we may not accept it. If we do not accept your OSFR evidence, then we will send you a written notification stating:
(1) That your evidence is not acceptable;
(2) Why your evidence is unacceptable; and
(3) The amount of time you are allowed to submit acceptable evidence without being subject to civil penalty under § 253.51.
(b) MMS may immediately and without prior notice invalidate your OSFR demonstration if you:
(1) Are no longer eligible to be the designated applicant for a COF included in your demonstration; or
(2) Permit the cancellation or termination of the insurance policy, surety bond, or indemnity upon which the continued validity of the demonstration is based.
(c) If MMS determines you are not complying with the requirements of this part for any reason other than paragraph (b) of this section, we will notify you of our intent to invalidate your OSFR demonstration and specify the corrective action needed. Unless you take the corrective action MMS specifies within 15 calendar days from the date you receive such a notice, we will invalidate your OSFR demonstration.
§ 253.51
What are the penalties for not complying with this part?
(a) If you fail to comply with the financial responsibility requirements of OPA at 33 U.S.C. 2716 or with the requirements of this part, then you may be liable for a civil penalty of up to $27,500 per COF per day of violation (that is, each day a COF is operated without acceptable evidence of OSFR).
(b) MMS will determine the date of a noncompliance. MMS will assess penalties in accordance with an OSFR penalty schedule using the procedures found at 30 CFR part 250, subpart N. You may obtain a copy of the penalty schedule from MMS at the address in § 253.45.
(c) MMS may assess a civil penalty against you that is greater or less than the amount in the penalty schedule after taking into account the factors in section 4303(a) of OPA (33 U.S.C. 2716a).
(d) If you fail to correct a deficiency in the OSFR evidence for a COF, then the Director may suspend operation of a COF in the OCS under 30 CFR 250.170 or seek judicial relief, including an order suspending the operation of any COF.
[63 FR 42711, Aug. 11, 1998, as amended at 64 FR 72794, Dec. 28, 1999; 72 FR 8899, Feb. 28, 2007]

Subpart F—Claims for Oil-Spill Removal Costs and Damages
§ 253.60
To whom may I present a claim?
(a) If you are a claimant, you must present your claim first to the designated applicant for the COF that is the source of the incident resulting in your claim. If, however, the designated applicant has filed a petition for bankruptcy under 11 U.S.C. chapter 7 or 11, you may present your claim first to any of the designated applicant's guarantors.
(b) If the claim you present to the designated applicant or guarantor is denied or not paid within 90 days after you first present it or advertising begins, whichever is later, then you may seek any of the following remedies that apply:
If the reason for denial or nonpayment is | then you may elect to
(1) Not an assertion of insolvency or petition in bankruptcy under 11 U.S.C. chapter 7 or 11 | (i) Present your claim to any of the responsible parties for the COF; or (ii) Initiate a lawsuit against the designated applicant and/or any of the responsible parties for the COF; or (iii) Present your claim to the Fund using the procedures at 33 CFR part 136.
(2) An assertion of insolvency or petition in bankruptcy under 11 U.S.C. chapter 7 or 11 | (i) Pursue any of the remedies in items (1)(i) through (iii) of this table; or (ii) Present your claim to any of the designated applicant's guarantors; or (iii) Initiate a lawsuit against any of the designated applicant's guarantors.
(c) If no one has resolved your claim to your satisfaction using the remedy that you elected under paragraph (b) of this section, then you may pursue another available remedy, unless the Fund has denied your claim or a court of competent jurisdiction has ruled against your claim. You may not pursue more than one remedy at a time.
(d) You may ask MMS to assist you in determining whether a guarantor may be liable for your claim. Send your request for assistance to the address listed in § 253.45. You must include any information you have regarding the existence or identity of possible guarantors.
§ 253.61
When is a guarantor subject to direct action for claims?
(a) If you are a guarantor, then you are subject to direct action for any claim asserted by:
(1) The United States for any compensation paid by the Fund under OPA, including compensation claim processing costs; and
(2) A claimant other than the United States if the designated applicant has:
(i) Denied or failed to pay a claim because of being insolvent; or
(ii) Filed a petition in bankruptcy under 11 U.S.C. chapters 7 or 11.
(b) If you participate in an insurance guaranty for a COF incident (i.e., oil-spill discharge or substantial threat of the discharge of oil) that is subject to claims under this part, then your maximum, aggregate liability for those claims is equal to your quota share of the insurance guaranty.
§ 253.62
What are the designated applicant's notification obligations regarding a claim?
If you are a designated applicant, and you receive a claim for removal costs and damages, then within 15 calendar days of receipt of a claim you must notify:
(a) Your guarantors; and
(b) The responsible parties for whom you are acting as the designated applicant.
Pt. 253, App.

Appendix to Part 253—List of U.S. Geological Survey Topographic Maps
Alabama (1:24,000 scale): Bellefontaine; Bon Secour Bay; Bridgehead; Coden; Daphne; Fort Morgan; Fort Morgan NW; Grand Bay; Grand Bay SW; Gulf Shores; Heron Bay; Hollingers Island; Isle Aux Herbes; Kreole; Lillian; Little Dauphin Island; Little Point Clear; Magnolia Springs; Mobile; Orange Beach; Perdido Beach; Petit Bois Island; Petit Bois Pass; Pine Beach; Point Clear; Saint Andrews Bay; West Pensacola.
Alaska (1:63,360 scale): Afognak (A-1, A-2, A-3, A-4, A-5, A-0&B-0, B-1, B-2, B-3, C-1&2, C-2&3, C-5, C-6, D-1, D-4, D-5); Anchorage (A-1, A-2, A-3, A-4, A-8, B-7, B-8); Barrow (A-1, A-2, A-3, A-4, A-5, B-3, B-4); Baird Mts. (A-6); Barter Island (A-3, A-4, A-5); Beechy Point (A-1, A-2, B-1, B-2, B-3, B-4, B-5, C-4, C-5); Bering Glacier (A-1, A-2, A-3, A-4, A-5, A-6, A-7, A-8); Black (A-1, A-2, B-1, C-1); Blying Sound (C-7, C-8, D-1&2, D-3, D-4, D-5, D-6, D-7, D-8); Candle (D-6); Cordova (A-1, A-2, A-3, A-4, A-7&8, B-2, B-3, B-4, B-5, B-6, B-7, B-8, C-5, C-6, C-7, C-8, D-6, D-7, D-8); De Long Mts. (D-4, D-5); Demarcation Point (C-1, C-2, D-2, D-3); Flaxman Island (A-1, A-3, A-4, A-5, B-5); Harrison Bay (B-1, B-2, B-3, B-4, C-1, C-3, C-4, C-5, D-4, D-5); Icy Bay (D1, D-2&3); Iliamna (A-2, A-3, A-4, B-2, B-3, C-1, C-2, D-1); Karluk (A-1, A-2, B-2, B-3, C-1, C-2, C-4&5, C-6); Kenai (A-4, A-5, A-7, A-8, B-4, B-6, B-7, B-8, C-4, C-5, C-6, C-7, D-1, D-2, D-3, D-4, D-5); Kodiak (A-3, A-4, A-5, A-6, B-1&2, B-3, B-4, B-6, C-1, C-2, C-3, C-5, C-6, D-1, D-2, D-3, D-4, D-5, D-6); Kotzebue (A-1, A-2, A-3, A-4, B-4, B-6, C-1, C-4, C-5, C-6, D-1, D-2); Kwiguk (C-6, D-6); Meade River (D-1, D-3, D-4, D-5); Middleton Island (B-7, D-1&2); Mt. Katmai (A-1, A-2, A-3; B-1); Mt. Michelson (D-1, D-2, D-3); Mt. St. Elias (A-5); Noatak (A-1, A-2, A-3, A-4, B-4, C-4, C-5, D-6, D-7); Nome (B-1, C-1, C-2, C-3, D-3, D-4, D-7); Norton Bay (A-4, B-4, B-5, B-6, C-4, C-5, C-6, D-4, D-5, D-6); Point Hope (A-1, A-2, B-2, B-3, C-2, C-3, D-1, D-2); Point Lay (A-3&4, B-2&3, C-2, D-1, D-2); Selawik (A-5, A-6, B-5, B-6, C-5, C-6, D-6); Seldovia (A-3, A-4, A-5, A-6, B-1, B-2, B-3, B-4, B-5, B-6, C-1, C-2, C-3, C-4, C-5, D-1, D-3, D-4, D-5, D-8); Seward (A-1, A-2, A-3, A-4, A-5, A-6, A-7, B-1, B-2, B-3, B-4, B-5, C-1, C-2, C-3, C-4, C-5, D-1, D-2, D-3, D-4, D-5, D-6, D-7, D-8); Shishmaref (A-2, A-3, A-4, B-1, B-2, B-3); Solomon (B-2, B-3, B-6, C-1, C-2, C-3, C-4, C-5, C-6); St. Michael (A-2, A-3, A-4, A-5, A-6, B-1, B-2, C-1, C-2); Teller (A-2, A-3, A-4, B-3, B-4, B-5, B-6, C-6, C-7, D-4, D-5, D-6, D-8); Teshekpuk (D-1, D-2, D-3, D-4, D-5); Tyonek (A-1, A-2, A-3, A-4, B-1, B-2); Unalakleet (B-5, B-6, C-4, C-5, D-4); Valdez (A-7, A-8); Wainwright (A-5, A-6&7, B-2, B-3, B-4, B-5&6, C-2, C-3 , D-1, D-2; Yakutat (A-1, A-2, A-2, B-3, B-4, B-5, C-4, C-5, C-6, C-7, C-8, D-3, D-4, D-5, D-6, D-8).
California (1:24,000 scale): Arroyo Grande NE; Beverly Hills; Carpinteria; Casmalia; Dana Point; Del Mar; Dos Pueblos Canyon; Encinitas; Gaviota; Goleta; Guadalupe; Imperial Beach; Laguna Beach; La Jolla; Las Pulgas Canyon; Lompoc Hills; Long Beach; Los Alamitos; Malibu Beach; Morro Bay South; National City; Newport Beach; Oceano; Oceanside; Oxnard; Pismo Beach; Pitas Point; Point Arguello; Point Conception; Point Dune; Point Loma; Point Mugu; Point Sal; Port San Luis; Rancho Santa Fe; Redondo Beach; Sacate; San Clemente; San Juan Capistrano; San Luis Rey; San Onofre Bluff; San Pedro; Santa Barbara; Saticoy; Seal Beach; Surf; Tajiguas; Topanga; Torrance; Tranquillon Mountain; Triunfo Pass; Tustin; Venice; Ventura; White Ledge Peak.
Florida (1:24,000 scale): Allanton; Alligator Bay; Anna Maria; Apalachicola; Aripeka; Bayport; Beacon Beach; Beacon Hill; Bee Ridge; Belle Meade; Belle Meade NW; Beverly; Big Lostmans Bay; Bird Keys; Bokeelia; Bonita Springs; Bradenton; Bradenton Beach; Bruce; Bunker; Cape Romano; Cape Saint George; Cape San Blas; Captiva; Carrabelle; Cedar Key; Chassahowitzka; Chassahowitzka Bay; Chiefland SW; Choctaw Beach; Chokoloskee; Clearwater; Clive Key; Cobb Rocks; Cockroach Bay; Crawfordville East; Crooked Island; Crooked Point; Cross City SW; Crystal River; Destin; Dog Island; Dunedin; East Pass; Egmont Key; El Jobean; Elfers; Englewood; Englewood NW; Estero; Everglades City; Fivay Junction; Flamingo; Fort Barrancas; Fort Myers Beach; Fort Myers SW; Fort Walton Beach; Freeport; Gandy Bridge; Garcon Point; Gator Hook Swamp; Gibsonton; Goose Island; Grayton Beach; Green Point; Gulf Breeze; Harney River; Harold SE; Holley; Holt SW; Homosassa; Horseshoe Beach; Indian Pass; Jackson River; Jena; Keaton Beach; Laguna Beach; Lake Ingraham East; Lake Ingraham West; Lake Wimico; Laurel; Lebanon Station; Lighthouse Point; Lillian; Long Point; Lostmans River Ranger Station; Manlin Hammock; Marco Island; Mary Esther; Matlacha; McIntyre; Milton South; Miramar Beach; Myakka River; Naples North; Naples South; Navarre; New Inlet; Niceville; Nutall Rise; Ochopee; Okefenokee Slough; Oldsmar; Orange Beach; Oriole Beach; Overstreet; Ozello; Pace; Palmetto; Panama City; Panama City Beach; Panther Key; Pass-A-Grille Beach; Pavillion Key; Pensacola; Perdido Bay; Pickett Bay; Pine Island Center; Placida; Plover Key; Point Washington; Port Boca Grande; Port Richey; Port Richey NE; Port Saint Joe; Port Tampa; Punta Gorda; Punta Gorda SE; Punta Gorda SW; Red Head; Red Level; Rock Islands; Royal Palm Hammock; Safety Harbor; Saint Joseph Point; Saint Joseph Spit; Saint Marks; Saint Marks NE; Saint Petersburg; Saint Teresa Beach; Salem SW; Sandy Key; Sanibel; Sarasota; Seahorse Key; Seminole; Seminole Hills; Shark Point; Shark River Island; Shired Island; Snipe Island; Sopchoppy; South of Holley; Southport; Sprague Island; Spring Creek; Springfield; Steinhatchee; Steinhatchee SE; Steinhatchee SW; Sugar Hill; Sumner; Suwannee; Tampa; Tarpon Springs; Valparaiso; Venice; Vista; Waccassasa Bay; Ward Basin; Warrior Swamp; Weavers Station; Weeki Wachee Spring; West Bay; West Pass; West Pensacola; Whitewater Bay West; Withlacoochee Bay; Wulfert; Yankeetown.
Louisiana (1:24,000 scale): Alligator Point; Barataria Pass; Bastian Bay; Bay Batiste; Bay Coquette; Bay Courant; Bay Dosgris; Bay Ronquille; Bay Tambour; Bayou Blanc; Bayou Lucien; Belle Isle; Belle Pass; Big Constance Lake; Black Bay North; Black Bay South; Breton Islands; Breton Islands SE; Buras; Burrwood Bayou East; Burwood Bayou West; Calumet Island; Cameron; Caminada Pass; Cat Island; Cat Island Pass; Central Isles Dernieres; Chandeleur Light; Chef Mentur; Cheniere Au Tigre; Cocodrie; Coquille Point; Cow Island; Creole; Cypremort Point; Deep Lake; Dixon Bay; Dog Lake; Door Point; East Bay Junop; Eastern Isles; Dernieres; Ellerslie; Empire; English Lookout; False Mouth Bayou; Fearman Lake; Floating Turf Bayou; Fourleague Bay; Franklin; Freemason Island; Garden Island Pass; Grand Bayou; Grand Bayou du Large; Grand Chenier; Grand Gosier Islands; Grand Isle; Hackberry Beach; Hammock Lake; Happy Jack; Hebert Lake; Hell Hole Bayou; Hog Bayou; Holly Beach; Intercoastal City; Isle Au Pitre; Jacko Bay; Johnson Bayou; Kemper; Lake Athanasio; Lake Cuatro Caballo; Lake Eloi; Lake Eugene; Lake Felicity; Lake La Graisse; Lake Merchant; Lake Point; Lake Salve; Lake Tambour; Leeville; Lena Lagoon; Lost Lake; Main Pass; Malheureux Point; Marone Point; Martello Castle; Mink Bayou; Mitchell Key; Morgan City SW; Morgan Harbor; Mound Point; Mulberry Island East; Mulberry Island West; New Harbor Islands; North Islands; Oak Mound Bayou; Oyster Bayou; Pass A Loutre East; Pass A Loutre West; Pass du Bois; Pass Tante Phine; Pecan Island; Pelican Pass; Peveto Beach; Pilottown; Plumb Bayou; Point Au Fer; Point Au Fer NE; Point Chevreuil; Point Chicot; Port Arthur South; Port Sulphur; Pte. Aux Marchuttes; Proctor Point; Pumpkin Islands; Redfish Point; Rollover Lake; Sabine Pass; Saint Joe Pass; Smith Bayou; South of South Pass; South Pass; Stake Islands; Taylor Pass; Texas Point; Three Mile Bay; Tigre Lagoon; Timbalier Island; Triumph; Venice; Weeks; West of Johnson Bayou; Western Isles Dernieres; Wilkinson Bay; Yscloskey.
Mississippi (1:24,000 scale): Bay Saint Louis; Biloxi; Cat Island; Chandeleur Light; Deer Island; Dog Keys Pass; English Lookout; Gautier North; Gautier South; Grand Bay SW; Gulfport North; Gulfport NW; Gulfport South; Horn Island East; Horn Island West; Isle Au Pitre; Kreole; Ocean Springs; Pascagoula North; Pascagoula South; Pass Christian; Petit Bois Island; Saint Joe Pass; Ship Island; Waveland.
Texas (1:24,000 scale): Allyns Bright; Anahuac; Aransas Pass; Austwell; Bacliff; Bayside; Big Hill Bayou; Brown Cedar Cut; Caplen; Carancahua Pass; Cedar Lakes East; Cedar Lakes West; Cedar Lane NE; Christmas Point; Clam Lake; Corpus Christi; Cove; Crane Islands NW; Crane Islands SW; Decros Point; Dressing Point; Estes; Flake; Freeport; Frozen Point; Galveston; Green Island; Hawk Island; High Island; Hitchcock; Hoskins Mound; Jones Creek; Keller Bay; Kleberg Point; La Comal; La Leona; La Parra Ranch NE; Laguna Vista; Lake Austin; Lake Como; Lake Stephenson; Lamar; Long Island; Los Amigos; Windmill; Maria Estella Well; Matagorda; Matagorda SW; Mesquite Bay; Mission Bay; Morgans Point; Mosquito Point; Mouth of Rio Grande; Mud Lake; North of Port Isabel NW; North of Port Isabel SW; Oak Island; Olivia; Oso Creek NE; Oyster Creek; Palacios; Palacios NE; Palacios Point; Palacios SE; Panther Point; Panther Point NE; Pass Cavallo SW; Pita Island; Point Comfort; Point of Rocks; Port Aransas; Port Arthur South; Port Bolivar; Port Ingleside; Port Isabel; Port Isabel NW; Port Lavaca East; Port Mansfield; Port O'Connor; Portland; Potrero Cortado; Potrero Lopeno NW; Potrero Lopeno SE; Potrero Lopeno SW; Rockport; Sabine Pass; San Luis Pass; Sargent; Sea Isle; Seadrift; Seadrift NE; Smith Point; South Bird Island; South Bird Island NW; South Bird Island SE; South of Palacios Point; South of Potrero Lopeno NE; South of Potrero Lopeno NW; South of Potrero Lopeno SE; South of Star Lake; St. Charles Bay; St. Charles Bay SE; St. Charles Bay SW; Star Lake; Texas City; Texas Point; The Jetties; Three Islands; Tivoli SE; Turtle Bay; Umbrella Point; Virginia Point; West of Johnson Bayou; Whites Ranch; Yarborough Pass.
Pt. 254

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

Subpart A—General
Sec.
254.1
Who must submit a spill-response plan?
254.2
When must I submit a response plan?
254.3
May I cover more than one facility in my response plan?
254.4
May I reference other documents in my response plan?
254.5
General response plan requirements.
254.6
Definitions.
254.7
How do I submit my response plan to the MMS?
254.8
May I appeal decisions under this part?
254.9
Authority for information collection.

Subpart B—Oil-Spill Response Plans for Outer Continental Shelf Facilities
254.20
Purpose.
254.21
How must I format my response plan?
254.22
What information must I include in the “Introduction and plan contents” section?
254.23
What information must I include in the “Emergency response action plan” section?
254.24
What information must I include in the “Equipment inventories” appendix?
254.25
What information must I include in the “Contractual agreements” appendix?
254.26
What information must I include in the “Worst case discharge scenario” appendix?
254.27
What information must I include in the “Dispersant use plan” appendix?
254.28
What information must I include in the “In situ burning plan” appendix?
254.29
What information must I include in the “Training and drills” appendix?
254.30
When must I revise my response plan?

Subpart C—Related Requirements for Outer Continental Shelf Facilities
254.40
Records.
254.41
Training your response personnel.
254.42
Exercises for your response personnel and equipment.
254.43
Maintenance and periodic inspection of response equipment.
254.44
Calculating response equipment effective daily recovery capacities.
254.45
Verifying the capabilities of your response equipment.
254.46
Whom do I notify if an oil spill occurs?
254.47
Determining the volume of oil of your worst case discharge scenario.

Subpart D—Oil-Spill Response Requirements for Facilities Located in State Waters Seaward of the Coast Line
254.50
Spill-response plans for facilities located in State waters seaward of the coast line.
254.51
Modifying an existing OCS response plan.
254.52
Following the format for an OCS response plan.
254.53
Submitting a response plan developed under State requirements.
254.54
Spill prevention for facilities located in State waters seaward of the coast line.

Authority:
33 U.S.C. 1321

Source:
62 FR 13996, Mar. 25, 1997, unless otherwise noted.

Subpart A—General
§ 254.1
Who must submit a spill-response plan?
(a) If you are the owner or operator of an oil handling, storage, or transportation facility, and it is located seaward of the coast line, you must submit a spill-response plan to MMS for approval. Your spill-response plan must demonstrate that you can respond quickly and effectively whenever oil is discharged from your facility. Refer to § 254.6 for the definitions of “oil,” “facility,” and “coast line” if you have any doubts about whether to submit a plan.
(b) You must maintain a current response plan for an abandoned facility until you physically remove or dismantle the facility or until the Regional Supervisor notifies you in writing that a plan is no longer required.
(c) Owners or operators of offshore pipelines carrying essentially dry gas do not need to submit a plan. You must, however, submit a plan for a pipeline that carries:
(1) Oil;
(2) Condensate that has been injected into the pipeline; or
(3) Gas and naturally occurring condensate.
(d) If you are in doubt as to whether you must submit a plan for an offshore facility or pipeline, you should check with the Regional Supervisor.
(e) If your facility is located landward of the coast line, but you believe your facility is sufficiently similar to OCS facilities that it should be regulated by MMS, you may contact the Regional Supervisor, offer to accept MMS jurisdiction over your facility, and request that MMS seek from the agency with jurisdiction over your facility a relinquishment of that jurisdiction.
§ 254.2
When must I submit a response plan?
(a) You must submit, and MMS must approve, a response plan that covers each facility located seaward of the coast line before you may use that facility. To continue operations, you must operate the facility in compliance with the plan.
(b) Despite the provisions of paragraph (a) of this section, you may operate your facility after you submit your plan while MMS reviews it for approval. To operate a facility without an approved plan, you must certify in writing to the Regional Supervisor that you have the capability to respond, to the maximum extent practicable, to a worst case discharge or a substantial threat of such a discharge. The certification must show that you have ensured by contract, or other means approved by the Regional Supervisor, the availability of private personnel and equipment necessary to respond to the discharge. Verification from the organization(s) providing the personnel and equipment must accompany the certification. MMS will not allow you to operate a facility for more than 2 years without an approved plan.
(c) If you have a plan that MMS already approved, you are not required to immediately rewrite the plan to comply with this part. You must, however, submit the information this regulation requires when submitting your first plan revision (see § 254.30) after the effective date of this rule. The Regional Supervisor may extend this deadline upon request.
§ 254.3
May I cover more than one facility in my response plan?
(a) Your response plan may be for a single lease or facility or a group of leases or facilities. All the leases or facilities in your plan must have the same owner or operator (including affiliates) and must be located in the same MMS Region (see definition of Regional Response Plan in § 254.6).
(b) Regional Response Plans must address all the elements required for a response plan in Subpart B, Oil Spill Response Plans for Outer Continental Shelf Facilities, or Subpart D, Oil Spill Response Requirements for Facilities Located in State Waters Seaward of the Coast Line, as appropriate.
(c) When developing a Regional Response Plan, you may group leases or facilities subject to the approval of the Regional Supervisor for the purposes of:
(1) Calculating response times;
(2) Determining quantities of response equipment;
(3) Conducting oil-spill trajectory analyses;
(4) Determining worst case discharge scenarios; and
(5) Identifying areas of special economic and environmental importance that may be impacted and the strategies for their protection.
(d) The Regional Supervisor may specify how to address the elements of a Regional Response Plan. The Regional Supervisor also may require that Regional Response Plans contain additional information if necessary for compliance with appropriate laws and regulations.
§ 254.4
May I reference other documents in my response plan?
You may reference information contained in other readily accessible documents in your response plan. Examples of documents that you may reference are the National Contingency Plan (NCP), Area Contingency Plan (ACP), MMS environmental documents, and Oil Spill Removal Organization (OSRO) documents that are readily accessible to the Regional Supervisor. You must ensure that the Regional Supervisor possesses or is provided with copies of all OSRO documents you reference. You should contact the Regional Supervisor if you want to know whether a reference is acceptable.
§ 254.5
General response plan requirements.
(a) The response plan must provide for response to an oil spill from the facility. You must immediately carry out the provisions of the plan whenever there is a release of oil from the facility. You must also carry out the training, equipment testing, and periodic drills described in the plan, and these measures must be sufficient to ensure the safety of the facility and to mitigate or prevent a discharge or a substantial threat of a discharge.
(b) The plan must be consistent with the National Contingency Plan and the appropriate Area Contingency Plan(s).
(c) Nothing in this part relieves you from taking all appropriate actions necessary to immediately abate the source of a spill and remove any spills of oil.
(d) In addition to the requirements listed in this part, you must provide any other information the Regional Supervisor requires for compliance with appropriate laws and regulations.
§ 254.6
Definitions.
For the purposes of this part:
Adverse weather conditions means weather conditions found in the operating area that make it difficult for response equipment and personnel to clean up or remove spilled oil or hazardous substances. These include, but are not limited to: Fog, inhospitable water and air temperatures, wind, sea ice, current, and sea states. It does not refer to conditions such as a hurricane, under which it would be dangerous or impossible to respond to a spill.
Area Contingency Plan means an Area Contingency Plan prepared and published under section 311(j) of the Federal Water Pollution Control Act (FWPCA).
Coast line means the line of ordinary low water along that portion of the coast which is in direct contact with the open sea and the line marking the seaward limit of inland waters.
Discharge means any emission (other than natural seepage), intentional or unintentional, and includes, but is not limited to, spilling, leaking, pumping, pouring, emitting, emptying, or dumping.
District Manager means the MMS officer with authority and responsibility for a district within an MMS Region.
Facility means any structure, group of structures, equipment, or device (other than a vessel) which is used for one or more of the following purposes: Exploring for, drilling for, producing, storing, handling, transferring, processing, or transporting oil. The term excludes deep-water ports and their associated pipelines as defined by the Deepwater Port Act of 1974, but includes other pipelines used for one or more of these purposes. A mobile offshore drilling unit is classified as a facility when engaged in drilling or downhole operations.
Maximum extent practicable means within the limitations of available technology, as well as the physical limitations of personnel, when responding to a worst case discharge in adverse weather conditions.
National Contingency Plan means the National Oil and Hazardous Substances Pollution Contingency Plan prepared and published under section 311(d) of the FWPCA, (33 U.S.C. 1321(d)) or revised under section 105 of the Comprehensive Environmental Response Compensation and Liability Act (42 U.S.C. 9605).
National Contingency Plan Product Schedule means a schedule of dispersants and other chemical or biological products, maintained by the Environmental Protection Agency, that may be authorized for use on oil discharges in accordance with the procedures found at 40 CFR 300.910.
Oil means oil of any kind or in any form, including but not limited to petroleum, fuel oil, sludge, oil refuse, and oil mixed with wastes other than dredged spoil. This also includes hydrocarbons produced at the wellhead in liquid form (includes distillates or condensate associated with produced natural gas), and condensate that has been separated from a gas prior to injection into a pipeline. It does not include petroleum, including crude oil or any fraction thereof, which is specifically listed or designated as a hazardous substance under paragraphs (A) through (F) of section 101(14) of the Comprehensive Environmental Response, Compensation, and Liability Act (42 U. S. C. 9601) and which is subject to the provisions of that Act. It also does not include animal fats and oils and greases and fish and marine mammal oils, within the meaning of paragraph (2) of section 61(a) of title 13, United States Code, and oils of vegetable origin, including oils from the seeds, nuts, and kernels referred to in paragraph (1)(A) of that section.
Oil spill removal organization (OSRO) means an entity contracted by an owner or operator to provide spill-response equipment and/or manpower in the event of an oil or hazardous substance spill.
Outer Continental Shelf means all submerged lands lying seaward and outside of the area of lands beneath navigable waters as defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of which the subsoil and seabed appertain to the United States and are subject to its jurisdiction and control.
Owner or operator means, in the case of an offshore facility, any person owning or operating such offshore facility. In the case of any abandoned offshore facility, it means the person who owned such facility immediately prior to such abandonment.
Pipeline means pipe and any associated equipment, appurtenance, or building used or intended for use in the transportation of oil located seaward of the coast line, except those used for deep-water ports. Pipelines do not include vessels such as barges or shuttle tankers used to transport oil from facilities located seaward of the coast line.
Qualified individual means an English-speaking representative of an owner or operator, located in the United States, available on a 24-hour basis, with full authority to obligate funds, carry out removal actions, and communicate with the appropriate Federal officials and the persons providing personnel and equipment in removal operations.
Regional Response Plan means a spill-response plan required by this part which covers multiple facilities or leases of an owner or operator, including affiliates, which are located in the same MMS Region.
Regional Supervisor means the MMS official with responsibility and authority for operations or other designated program functions within an MMS Region.
Remove means containment and cleanup of oil from water and shorelines or the taking of other actions as may be necessary to minimize or mitigate damage to the public health or welfare, including, but not limited to, fish, shellfish, wildlife, public and private property, shorelines, and beaches.
Spill is synonymous with “discharge” for the purposes of this part.
Spill management team means the trained persons identified in a response plan who staff the organizational structure to manage spill response.
Spill-response coordinator means a trained person charged with the responsibility and designated the commensurate authority for directing and coordinating response operations.
Spill-response operating team means the trained persons who respond to spills through deployment and operation of oil-spill response equipment.
State waters located seaward of the coast line means the belt of the seas measured from the coast line and extending seaward a distance of 3 miles (except the coast of Texas and the Gulf coast of Florida, where the State waters extend seaward a distance of 3 leagues).
You means the owner or the operator as defined in this section.
[62 FR 13996, Mar. 25, 1997, as amended at 71 FR 46400, Aug. 14, 2006]
§ 254.7
How do I submit my response plan to the MMS?
You must submit the number of copies of your response plan that the appropriate MMS regional office requires. If you prefer to use improved information technology such as electronic filing to submit your plan, ask the Regional Supervisor for further guidance.
(a) Send plans for facilities located seaward of the coast line of Alaska to: Minerals Management Service, Regional Supervisor, Field Operations, Alaska OCS Region, 949 East 36th Avenue, Anchorage, AK 99508-4302.
(b) Send plans for facilities in the Gulf of Mexico or Atlantic Ocean to: Minerals Management Service, Regional Supervisor, Field Operations, Gulf of Mexico OCS Region, 1201 Elmwood Park Boulevard, New Orleans, LA 70123-2394.
(c) Send plans for facilities in the Pacific Ocean (except seaward of the coast line of Alaska) to: Minerals Management Service, Regional Supervisor, Office of Development Operations and Safety, Pacific OCS Region, 770 Paseo Camarillo, Camarillo, CA 93010-6064.
§ 254.8
May I appeal decisions under this part?
See 30 CFR part 290 for instructions on how to appeal any order or decision that we issue under this part.
[65 FR 3857, Jan. 25, 2000]
§ 254.9
Authority for information collection.
(a) The Office of Management and Budget (OMB) has approved the information collection requirements in this part under 44 U.S.C. 3501 et seq. OMB assigned the control number 1010-0091. The title of this information collection is “30 CFR Part 254, Oil Spill Response Requirements for Facilities Located Seaward of the Coast line.”
(b) MMS collects this information to ensure that the owner or operator of an offshore facility is prepared to respond to an oil spill. MMS uses the information to verify compliance with the mandates of the Oil Pollution Act of 1990 (OPA). The requirement to submit this information is mandatory. No confidential or proprietary information is collected.
(c) An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number.
(d) Send comments regarding any aspect of the collection of information under this part, including suggestions for reducing the burden, to the Information Collection Clearance Officer, Minerals Management Service, Mail Stop 4230, 1849 C Street, NW., Washington, DC 20240.
[62 FR 13996, Mar. 25, 1997, as amended at 62 FR 18041, Apr. 14, 1997; 65 FR 2876, Jan. 19, 2000]

Subpart B—Oil-Spill Response Plans for Outer Continental Shelf Facilities
§ 254.20
Purpose.
This subpart describes the requirements for preparing spill-response plans for facilities located on the OCS.
§ 254.21
How must I format my response plan?
(a) You must divide your response plan for OCS facilities into the sections specified in paragraph (b) and explained in the other sections of this subpart. The plan must have an easily found marker identifying each section. You may use an alternate format if you include a cross-reference table to identify the location of required sections. You may use alternate contents if you can demonstrate to the Regional Supervisor that they provide for equal or greater levels of preparedness.
(b) Your plan must include:
(1) Introduction and plan contents.
(2) Emergency response action plan.
(3) Appendices:
(i) Equipment inventory.
(ii) Contractual agreements.
(iii) Worst case discharge scenario.
(iv) Dispersant use plan.
(v) In situ burning plan.
(vi) Training and drills.
§ 254.22
What information must I include in the “Introduction and plan contents” section?
The “Introduction and plan contents” section must provide:
(a) Identification of the facility the plan covers, including its location and type;
(b) A table of contents;
(c) A record of changes made to the plan; and
(d) A cross-reference table, if needed, because you are using an alternate format for your plan.
§ 254.23
What information must I include in the “Emergency response action plan” section?
The “Emergency response action plan”section is the core of the response plan. Put information in easy-to-use formats such as flow charts or tables where appropriate. This section must include:
(a) Designation, by name or position, of a trained qualified individual (QI) who has full authority to implement removal actions and ensure immediate notification of appropriate Federal officials and response personnel.
(b) Designation, by name or position, of a trained spill management team available on a 24-hour basis. The team must include a trained spill-response coordinator and alternate(s) who have the responsibility and authority to direct and coordinate response operations on your behalf. You must describe the team's organizational structure as well as the responsibilities and authorities of each position on the spill management team.
(c) Description of a spill-response operating team. Team members must be trained and available on a 24-hour basis to deploy and operate spill-response equipment. They must be able to respond within a reasonable minimum specified time. You must include the number and types of personnel available from each identified labor source.
(d) A planned location for a spill-response operations center and provisions for primary and alternate communications systems available for use in coordinating and directing spill-response operations. You must provide telephone numbers for the response operations center. You also must provide any facsimile numbers and primary and secondary radio frequencies that will be used.
(e) A listing of the types and characteristics of the oil handled, stored, or transported at the facility.
(f) Procedures for the early detection of a spill.
(g) Identification of procedures you will follow in the event of a spill or a substantial threat of a spill. The procedures should show appropriate response levels for differing spill sizes including those resulting from a fire or explosion. These will include, as appropriate:
(1) Your procedures for spill notification. The plan must provide for the use of the oil spill reporting forms included in the Area Contingency Plan or an equivalent reporting form.
(i) Your procedures must include a current list which identifies the following by name or position, corporate address, and telephone number (including facsimile number if applicable):
(A) The qualified individual;
(B) The spill-response coordinator and alternate(s); and
(C) Other spill-response management team members.
(ii) You must also provide names, telephone numbers, and addresses for the following:
(A) OSRO's that the plan cites;
(B) Federal, State, and local regulatory agencies that you must consult to obtain site specific environmental information; and
(C) Federal, State, and local regulatory agencies that you must notify when an oil spill occurs.
(2) Your methods to monitor and predict spill movement;
(3) Your methods to identify and prioritize the beaches, waterfowl, other marine and shoreline resources, and areas of special economic and environmental importance;
(4) Your methods to protect beaches, waterfowl, other marine and shoreline resources, and areas of special economic or environmental importance;
(5) Your methods to ensure that containment and recovery equipment as well as the response personnel are mobilized and deployed at the spill site;
(6) Your methods to ensure that devices for the storage of recovered oil are sufficient to allow containment and recovery operations to continue without interruption;
(7) Your procedures to remove oil and oiled debris from shallow waters and along shorelines and rehabilitating waterfowl which become oiled;
(8) Your procedures to store, transfer, and dispose of recovered oil and oil-contaminated materials and to ensure that all disposal is in accordance with Federal, State, and local requirements; and
(9) Your methods to implement your dispersant use plan and your in situ burning plan.
§ 254.24
What information must I include in the “Equipment inventory” appendix?
Your “Equipment inventory appendix” must include:
(a) An inventory of spill-response materials and supplies, services, equipment, and response vessels available locally and regionally. You must identify each supplier and provide their locations and telephone numbers.
(b) A description of the procedures for inspecting and maintaining spill-response equipment in accordance with § 254.43.
§ 254.25
What information must I include in the “Contractual agreements” appendix?
Your “Contractual agreements” appendix must furnish proof of any contracts or membership agreements with OSRO's, cooperatives, spill-response service providers, or spill management team members who are not your employees that you cite in the plan. To provide this proof, submit copies of the contracts or membership agreements or certify that contracts or membership agreements are in effect. The contract or membership agreement must include provisions for ensuring the availability of the personnel and/or equipment on a 24-hour-per-day basis.
§ 254.26
What information must I include in the “Worst case discharge scenario” appendix?
The discussion of your worst case discharge scenario must include all of the following elements:
(a) The volume of your worst case discharge scenario determined using the criteria in § 254.47. Provide any assumptions made and the supporting calculations used to determine this volume.
(b) An appropriate trajectory analysis specific to the area in which the facility is located. The analysis must identify onshore and offshore areas that a discharge potentially could affect. The trajectory analysis chosen must reflect the maximum distance from the facility that oil could move in a time period that it reasonably could be expected to persist in the environment.
(c) A list of the resources of special economic or environmental importance that potentially could be impacted in the areas identified by your trajectory analysis. You also must state the strategies that you will use for their protection. At a minimum, this list must include those resources of special economic and environmental importance, if any, specified in the appropriate Area Contingency Plan(s).
(d) A discussion of your response to your worst case discharge scenario in adverse weather conditions. This discussion must include:
(1) A description of the response equipment that you will use to contain and recover the discharge to the maximum extent practicable. This description must include the types, location(s) and owner, quantity, and capabilities of the equipment. You also must include the effective daily recovery capacities, where applicable. You must calculate the effective daily recovery capacities using the methods described in § 254.44. For operations at a drilling or production facility, your scenario must show how you will cope with the initial spill volume upon arrival at the scene and then support operations for a blowout lasting 30 days.
(2) A description of the personnel, materials, and support vessels that would be necessary to ensure that the identified response equipment is deployed and operated promptly and effectively. Your description must include the location and owner of these resources as well as the quantities and types (if applicable);
(3) A description of your oil storage, transfer, and disposal equipment. Your description must include the types, location and owner, quantity, and capacities of the equipment; and
(4) An estimation of the individual times needed for:
(i) Procurement of the identified containment, recovery, and storage equipment;
(ii) Procurement of equipment transportation vessel(s);
(iii) Procurement of personnel to load and operate the equipment;
(iv) Equipment loadout (transfer of equipment to transportation vessel(s));
(v) Travel to the deployment site (including any time required for travel from an equipment storage area); and
(vi) Equipment deployment.
(e) In preparing the discussion required by paragraph (d) of this section, you must:
(1) Ensure that the response equipment, materials, support vessels, and strategies listed are suitable, within the limits of current technology, for the range of environmental conditions anticipated at your facility; and
(2) Use standardized, defined terms to describe the range of environmental conditions anticipated and the capabilities of response equipment. Examples of acceptable terms include those defined in American Society for Testing of Materials (ASTM) publication F625-94, Standard Practice for Describing Environmental Conditions Relevant to Spill Control Systems for Use on Water, and ASTM F818-93, Standard Definitions Relating to Spill Response Barriers.
§ 254.27
What information must I include in the “Dispersant use plan” appendix?
Your dispersant use plan must be consistent with the National Contingency Plan Product Schedule and other provisions of the National Contingency Plan and the appropriate Area Contingency Plan(s). The plan must include:
(a) An inventory and a location of the dispersants and other chemical or biological products which you might use on the oils handled, stored, or transported at the facility;
(b) A summary of toxicity data for these products;
(c) A description and a location of any application equipment required as well as an estimate of the time to commence application after approval is obtained;
(d) A discussion of the application procedures;
(e) A discussion of the conditions under which product use may be requested; and
(f) An outline of the procedures you must follow in obtaining approval for product use.
§ 254.28
What information must I include in the “In situ burning plan” appendix?
Your in situ burning plan must be consistent with any guidelines authorized by the National Contingency Plan and the appropriate Area Contingency Plan(s). Your in situ burning plan must include:
(a) A description of the in situ burn equipment including its availability, location, and owner;
(b) A discussion of your in situ burning procedures, including provisions for ignition of an oil spill;
(c) A discussion of environmental effects of an in situ burn;
(d) Your guidelines for well control and safety of personnel and property;
(e) A discussion of the circumstances in which in situ burning may be appropriate;
(f) Your guidelines for making the decision to ignite; and
(g) An outline of the procedures you must follow to obtain approval for an in situ burn.
§ 254.29
What information must I include in the “Training and drills” appendix?
Your “Training and drills” appendix must:
(a) Identify and include the dates of the training provided to members of the spill-response management team and the qualified individual. The types of training given to the members of the spill-response operating team also must be described. The training requirements for your spill management team and your spill-response operating team are specified in § 254.41. You must designate a location where you keep course completion certificates or attendance records for this training.
(b) Describe in detail your plans for satisfying the exercise requirements of § 254.42. You must designate a location where you keep the records of these exercises.
§ 254.30
When must I revise my response plan?
(a) You must review your response plan at least every 2 years and submit all resulting modifications to the Regional Supervisor. If this review does not result in modifications, you must inform the Regional Supervisor in writing that there are no changes.
(b) You must submit revisions to your plan for approval within 15 days whenever:
(1) A change occurs which significantly reduces your response capabilities;
(2) A significant change occurs in the worst case discharge scenario or in the type of oil being handled, stored, or transported at the facility;
(3) There is a change in the name(s) or capabilities of the oil spill removal organizations cited in the plan; or
(4) There is a significant change to the Area Contingency Plan(s).
(c) The Regional Supervisor may require that you resubmit your plan if the plan has become outdated or if numerous revisions have made its use difficult.
(d) The Regional Supervisor will periodically review the equipment inventories of OSRO's to ensure that sufficient spill removal equipment is available to meet the cumulative needs of the owners and operators who cite these organizations in their plans.
(e) The Regional Supervisor may require you to revise your plan if significant inadequacies are indicated by:
(1) Periodic reviews (described in paragraph (d) of this section);
(2) Information obtained during drills or actual spill responses; or
(3) Other relevant information the Regional Supervisor obtained.

Subpart C—Related Requirements for Outer Continental Shelf Facilities
§ 254.40
Records.
You must make all records of services, personnel, and equipment provided by OSRO's or cooperatives available to any authorized MMS representative upon request.
§ 254.41
Training your response personnel.
(a) You must ensure that the members of your spill-response operating team who are responsible for operating response equipment attend hands-on training classes at least annually. This training must include the deployment and operation of the response equipment they will use. Those responsible for supervising the team must be trained annually in directing the deployment and use of the response equipment.
(b) You must ensure that the spill-response management team, including the spill-response coordinator and alternates, receives annual training. This training must include instruction on:
(1) Locations, intended use, deployment strategies, and the operational and logistical requirements of response equipment;
(2) Spill reporting procedures;
(3) Oil-spill trajectory analysis and predicting spill movement; and
(4) Any other responsibilities the spill management team may have.
(c) You must ensure that the qualified individual is sufficiently trained to perform his or her duties.
(d) You must keep all training certificates and training attendance records at the location designated in your response plan for at least 2 years. They must be made available to any authorized MMS representative upon request.
§ 254.42
Exercises for your response personnel and equipment.
(a) You must exercise your entire response plan at least once every 3 years (triennial exercise). You may satisfy this requirement by conducting separate exercises for individual parts of the plan over the 3-year period; you do not have to exercise your entire response plan at one time.
(b) In satisfying the triennial exercise requirement, you must, at a minimum, conduct:
(1) An annual spill management team tabletop exercise. The exercise must test the spill management team's organization, communication, and decisionmaking in managing a response. You must not reveal the spill scenario to team members before the exercise starts.
(2) An annual deployment exercise of response equipment identified in your plan that is staged at onshore locations. You must deploy and operate each type of equipment in each triennial period. However, it is not necessary to deploy and operate each individual piece of equipment.
(3) An annual notification exercise for each facility that is manned on a 24- hour basis. The exercise must test the ability of facility personnel to communicate pertinent information in a timely manner to the qualified individual.
(4) A semiannual deployment exercise of any response equipment which the MMS Regional Supervisor requires an owner or operator to maintain at the facility or on dedicated vessels. You must deploy and operate each type of this equipment at least once each year. Each type need not be deployed and operated at each exercise.
(c) During your exercises, you must simulate conditions in the area of operations, including seasonal weather variations, to the extent practicable. The exercises must cover a range of scenarios over the 3-year exercise period, simulating responses to large continuous spills, spills of short duration and limited volume, and your worst case discharge scenario.
(d) MMS will recognize and give credit for any documented exercise conducted that satisfies some part of the required triennial exercise. You will receive this credit whether the owner or operator, an OSRO, or a Government regulatory agency initiates the exercise. MMS will give you credit for an actual spill response if you evaluate the response and generate a proper record. Exercise documentation should include the following information:
(1) Type of exercise;
(2) Date and time of the exercise;
(3) Description of the exercise;
(4) Objectives met; and
(5) Lessons learned.
(e) All records of spill-response exercises must be maintained for the complete 3-year exercise cycle. Records should be maintained at the facility or at a corporate location designated in the plan. Records showing that OSRO's and oil spill removal cooperatives have deployed each type of equipment also must be maintained for the 3-year cycle.
(f) You must inform the Regional Supervisor of the date of any exercise required by paragraph (b)(1), (2), or (4) of this section at least 30 days before the exercise. This will allow MMS personnel the opportunity to witness any exercises.
(g) The Regional Supervisor periodically will initiate unannounced drills to test the spill response preparedness of owners and operators.
(h) The Regional Supervisor may require changes in the frequency or location of the required exercises, equipment to be deployed and operated, or deployment procedures or strategies. The Regional Supervisor may evaluate the results of the exercises and advise the owner or operator of any needed changes in response equipment, procedures, or strategies.
(i) Compliance with the National Preparedness for Response Exercise Program (PREP) Guidelines will satisfy the exercise requirements of this section. Copies of the PREP document may be obtained from the Regional Supervisor.
§ 254.43
Maintenance and periodic inspection of response equipment.
(a) You must ensure that the response equipment listed in your response plan is inspected at least monthly and is maintained, as necessary, to ensure optimal performance.
(b) You must ensure that records of the inspections and the maintenance activities are kept for at least 2 years and are made available to any authorized MMS representative upon request.
§ 254.44
Calculating response equipment effective daily recovery capacities.
(a) You are required by § 254.26(d)(1) to calculate the effective daily recovery capacity of the response equipment identified in your response plan that you would use to contain and recover your worst case discharge. You must calculate the effective daily recovery capacity of the equipment by multiplying the manufacturer's rated throughput capacity over a 24-hour period by 20 percent. This 20 percent efficiency factor takes into account the limitations of the recovery operations due to available daylight, sea state, temperature, viscosity, and emulsification of the oil being recovered. You must use this calculated rate to determine if you have sufficient recovery capacity to respond to your worst case discharge scenario.
(b) If you want to use a different efficiency factor for specific oil recovery devices, you must submit evidence to substantiate that efficiency factor. Adequate evidence includes verified performance data measured during actual spills or test data gathered according to the provisions of § 254.45 (b) and (c).
§ 254.45
Verifying the capabilities of your response equipment.
(a) The Regional Supervisor may require performance testing of any spill-response equipment listed in your response plan to verify its capabilities if the equipment:
(1) Has been modified;
(2) Has been damaged and repaired; or
(3) Has a claimed effective daily recovery capacity that is inconsistent with data otherwise available to MMS.
(b) You must conduct any required performance testing of booms in accordance with MMS-approved test criteria. You may use the document “Test Protocol for the Evaluation of Oil-Spill Containment Booms,” available from MMS, for guidance. Performance testing of skimmers also must be conducted in accordance with MMS approved test criteria. You may use the document “Suggested Test Protocol for the Evaluation of Oil Spill Skimmers for the OCS,” available from MMS, for guidance.
(c) You are responsible for any required testing of equipment performance and for the accuracy of the information submitted.
§ 254.46
Whom do I notify if an oil spill occurs?
(a) You must immediately notify the National Response Center (1-800-424-8802) if you observe:
(1) An oil spill from your facility;
(2) An oil spill from another offshore facility; or
(3) An offshore spill of unknown origin.
(b) In the event of a spill of 1 barrel or more from your facility, you must orally notify the Regional Supervisor without delay. You also must report spills from your facility of unknown size but thought to be 1 barrel or more.
(1) If a spill from your facility not originally reported to the Regional Supervisor is subsequently found to be 1 barrel or more, you must then report it without delay.
(2) You must file a written followup report for any spill from your facility of 1 barrel or more. The Regional Supervisor must receive this confirmation within 15 days after the spillage has been stopped. All reports must include the cause, location, volume, and remedial action taken. Reports of spills of more than 50 barrels must include information on the sea state, meteorological conditions, and the size and appearance of the slick. The Regional Supervisor may require additional information if it is determined that an analysis of the response is necessary.
(c) If you observe a spill resulting from operations at another offshore facility, you must immediately notify the responsible party and the Regional Supervisor.
§ 254.47
Determining the volume of oil of your worst case discharge scenario.
You must calculate the volume of oil of your worst case discharge scenario as follows:
(a) For an oil production platform facility, the size of your worst case discharge scenario is the sum of the following:
(1) The maximum capacity of all oil storage tanks and flow lines on the facility. Flow line volume may be estimated; and
(2) The volume of oil calculated to leak from a break in any pipelines connected to the facility considering shutdown time, the effect of hydrostatic pressure, gravity, frictional wall forces and other factors; and
(3) The daily production volume from an uncontrolled blowout of the highest capacity well associated with the facility. In determining the daily discharge rate, you must consider reservoir characteristics, casing/production tubing sizes, and historical production and reservoir pressure data. Your scenario must discuss how to respond to this well flowing for 30 days as required by § 254.26(d)(1).
(b) For exploratory or development drilling operations, the size of your worst case discharge scenario is the daily volume possible from an uncontrolled blowout. In determining the daily discharge rate, you must consider any known reservoir characteristics. If reservoir characteristics are unknown, you must consider the characteristics of any analog reservoirs from the area and give an explanation for the selection of the reservoir(s) used. Your scenario must discuss how to respond to this well flowing for 30 days as required by § 254.26(d)(1).
(c) For a pipeline facility, the size of your worst case discharge scenario is the volume possible from a pipeline break. You must calculate this volume as follows:
(1) Add the pipeline system leak detection time to the shutdown response time.
(2) Multiply the time calculated in paragraph (c)(1) of this section by the highest measured oil flow rate over the preceding 12-month period. For new pipelines, you should use the predicted oil flow rate in the calculation.
(3) Add to the volume calculated in paragraph (c)(2) of this section the total volume of oil that would leak from the pipeline after it is shut in. Calculate this volume by taking into account the effects of hydrostatic pressure, gravity, frictional wall forces, length of pipeline segment, tie-ins with other pipelines, and other factors.
(d) If your facility which stores, handles, transfers, processes, or transports oil does not fall into the categories listed in paragraph (a), (b), or (c) of this section, contact the Regional Supervisor for instructions on the calculation of the volume of your worst case discharge scenario.

Subpart D—Oil-Spill Response Requirements for Facilities Located in State Waters Seaward of the Coast Line
§ 254.50
Spill response plans for facilities located in State waters seaward of the coast line.
Owners or operators of facilities located in State waters seaward of the coast line must submit a spill-response plan to MMS for approval. You may choose one of three methods to comply with this requirement. The three methods are described in §§ 254.51, 254.52, and 254.53.
§ 254.51
Modifying an existing OCS response plan.
You may modify an existing response plan covering a lease or facility on the OCS to include a lease or facility in State waters located seaward of the coast line. Since this plan would cover more than one lease or facility, it would be considered a Regional Response Plan. You should refer to § 254.3 and contact the appropriate regional MMS office if you have any questions on how to prepare this Regional Response Plan.
§ 254.52
Following the format for an OCS response plan.
You may develop a response plan following the requirements for plans for OCS facilities found in subpart B of this part.
§ 254.53
Submitting a response plan developed under State requirements.
(a) You may submit a response plan to MMS for approval that you developed in accordance with the laws or regulations of the appropriate State. The plan must contain all the elements the State and OPA require and must:
(1) Be consistent with the requirements of the National Contingency Plan and appropriate Area Contingency Plan(s).
(2) Identify a qualified individual and require immediate communication between that person and appropriate Federal officials and response personnel if there is a spill.
(3) Identify any private personnel and equipment necessary to remove, to the maximum extent practicable, a worst case discharge as defined in § 254.47. The plan must provide proof of contractual services or other evidence of a contractual agreement with any OSRO's or spill management team members who are not employees of the owner or operator.
(4) Describe the training, equipment testing, periodic unannounced drills, and response actions of personnel at the facility. These must ensure both the safety of the facility and the mitigation or prevention of a discharge or the substantial threat of a discharge.
(5) Describe the procedures you will use to periodically update and resubmit the plan for approval of each significant change.
(b) Your plan developed under State requirements also must include the following information:
(1) A list of the facilities and leases the plan covers and a map showing their location;
(2) A list of the types of oil handled, stored, or transported at the facility;
(3) Name and address of the State agency to whom the plan was submitted;
(4) Date you submitted the plan to the State;
(5) If the plan received formal approval, the name of the approving organization, the date of approval, and a copy of the State agency's approval letter if one was issued; and
(6) Identification of any regulations or standards used in preparing the plan.
§ 254.54
Spill prevention for facilities located in State waters seaward of the coast line.
In addition to your response plan, you must submit to the Regional Supervisor a description of the steps you are taking to prevent spills of oil or mitigate a substantial threat of such a discharge. You must identify all State or Federal safety or pollution prevention requirements that apply to the prevention of oil spills from your facility, and demonstrate your compliance with these requirements. You also should include a description of industry safety and pollution prevention standards your facility meets. The Regional Supervisor may prescribe additional equipment or procedures for spill prevention if it is determined that your efforts to prevent spills do not reflect good industry practices.
Pt. 256

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

Subpart A—Outer Continental Shelf Oil, Gas, and Sulphur Management, General
Sec.
256.0
Authority for information collection.
256.1
Purpose.
256.2
Policy.
256.4
Authority.
256.5
Definitions.
256.7
Cross references.
256.8
Leasing maps and diagrams.
256.10
Information to States.
256.11
Helium.
256.12
Supplemental sales.

Subpart B—Oil and Gas Leasing Program
256.16
Receipt and consideration of nominations; public notice and participation.
256.17
Review by State and local governments and other persons.
256.19
Periodic consultation with interested parties.
256.20
Consideration of coastal zone management program.

Subpart C—Reports From Federal Agencies
256.22
General.

Subpart D—Call for Information and Nominations
256.23
Information on areas.
256.25
Areas near coastal States.

Subpart E—Area Identification and Tract Size
256.26
General.
256.28
Tract size.

Subpart F—Lease Sales
256.29
Proposed notice of sale.
256.31
State comments.
256.32
Notice of sale.

Subpart G—Issuance of Leases
256.35
Qualifications of lessees.
256.37
Lease term.
256.38
Joint bidding provisions.
256.40
Definitions.
256.41
Joint bidding requirements.
256.43
Chargeability for production.
256.44
Bids disqualified.
256.46
Submission of bids.
256.47
Award of leases.
256.49
Lease form.
256.50
Dating of leases.
Subpart H—Rentals and Royalties [Reserved]

Subpart I—Bonding
256.52
Bond requirements for an oil and gas or sulphur lease.
256.53
Additional bonds.
256.54
General requirements for bonds.
256.55
Lapse of bond.
256.56
Lease-specific abandonment accounts.
256.57
Using a third-party guarantee instead of a bond.
256.58
Termination of the period of liability and cancellation of a bond.
256.59
Forfeiture of bonds and/or other securities.

Subpart J—Assignments, Transfers, and Extensions
256.62
Assignment of lease or interest in lease.
256.63
Service fees.
256.64
How to file transfers.
256.65
Attorney General review.
256.67
Separate filings for assignments.
256.68
Effect of assignment of a particular tract.
256.70
Extension of lease by drilling or well reworking operations.
256.71
Directional drilling.
256.72
Compensatory payments as production.
256.73
Effect of suspensions on lease term.

Subpart K—Termination of Leases
256.76
Relinquishment of leases or parts of leases.
256.77
Cancellation of leases.

Subpart L—Section 6 Leases
256.79
Effect of regulations on lease.
256.80
Leases of other minerals.

Subpart M—Studies
256.82
Environmental studies.
Appendix A to Part 256—Oil and Gas Cash Bonus Bid

Authority:
43 U.S.C. 1331 et seq., 42 U.S.C. 6213, 31 U.S.C. 9701.

Source:
44 FR 38276, June 29, 1979, unless otherwise noted. Redesignated at 47 FR 47006, Oct. 22, 1982.

Subpart A—Outer Continental Shelf Oil, Gas, and Sulphur Management, General
§ 256.0
Authority for information collection.
(a) The Office of Management and Budget (OMB) has approved the information collection requirements in this part under 44 U.S.C. 3501 et seq. OMB assigned the control number 1010-0006. The title of this information collection is “30 CFR Part 256, Leasing of Sulphur or Oil and Gas in the Outer Continental Shelf.”
(b) MMS collects this information to determine if the applicant filing for a lease on the Outer Continental Shelf is qualified to hold such a lease. Response is required to obtain a benefit according to 43 U.S.C. 1331 et seq. MMS will protect proprietary information collected according to section 26 of the OCS Lands Act and 30 CFR 256.10.
(c) An agency may not conduct or sponsor, and a person is not required to respond to a collection of information unless it displays a currently valid OMB control number.
(d) Send comments regarding any aspect of the collection of information under this part, including suggestions for reducing the burden, to the Information Collection Clearance Officer, Minerals Management Service, Mail Stop 4230, 1849 C Street, NW., Washington, DC 20240.
[65 FR 2876, Jan. 19, 2000]
§ 256.1
Purpose.
The purpose of the regulations in this part is to establish the procedures under which the Secretary of the Interior (Secretary) will exercise the authority to administer a leasing program for oil, gas and sulphur. The procedures under which the Secretary will exercise the authority to administer a program to grant rights-of-way, rights-of-use and easements are addressed in other parts.
[64 FR 72795, Dec. 28, 1999]
§ 256.2
Policy.
The management of Outer Continental Shelf resources is to be conducted in accordance with the findings, purposes and policy directions provided by the Outer Continental Shelf Lands Act Amendments of 1978 (43 U.S.C. 1332, 1801, 1802), and other Executive, legislative, judicial and Departmental guidance. The Secretary of the Interior shall consider available environmental information in making decisions affecting Outer Continental Shelf resources.
§ 256.4
Authority.
The outer Continental Shelf Lands Act (OCSLA) (43 U.S.C. 1331 et seq.) authorizes the Secretary of the Interior to issue, on a competitive basis, leases for oil and gas, and sulphur, in submerged lands of the outer Continental Shelf (OCS). The Act authorizes the Secretary to grant rights-of-way, rights-of-use and easements through the submerged lands of the OCS. The Energy Policy and Conservation Act of 1975 (42 U.S.C. 6213), prohibits joint bidding by major oil and gas producers.
[64 FR 72795, Dec. 28, 1999]
§ 256.5
Definitions.
As used in this part, the term:
(a) Act refers to the Outer Continental Shelf Lands Act of August 7, 1953 (43 U.S.C. 1331 et seq.) as amended.
(b) Director means the Director, Minerals Management Service.
(c) OCS means the Outer Continental Shelf, as that term is defined in 43 U.S.C. 1331(a).
(d) Secretary means the Secretary of the Interior or an official authorized to act on the Secretary's behalf.
(e) MMS means the Minerals Management Service.
(f) Coastal zone means the coastal waters (including the lands therein and thereunder) and the adjacent shorelands (including the waters therein and thereunder), strongly influenced by each other and in proximity to the shorelines of the several coastal States, and includes islands, transition and intertidal areas, salt marshes, wetlands, and beaches, which zone extends seaward to the outer limit of the United States territorial sea and extends inland from the shore lines to the extent necessary to control shorelands, the uses of which have a direct and significant impact on the coastal waters, and the inward boundaries of which may be identified by the several coastal States, pursuant to the authority of section 305(b)(1) of the Coastal Zone Management Act of 1972 (16 U.S.C. 1454(b)(1));
(g) Affected State means, with respect to any program, plan, lease sale, or other activity, proposed, conducted, or approved pursuant to the provisions of the act, any State—
(1) The laws of which are declared, pursuant to section 4(a)(2) of the Act, to be the law of the United States for the portion of the Outer Continental Shelf on which such activity is, or is proposed to be conducted;
(2) Which is, or is proposed to be, directly connected by transportation facilities to any artificial island or structure referred to in section 4(a)(1) of the Act;
(3) Which is receiving, or in accordance with the proposed activity will receive, oil for processing, refining, or transshipment which was extracted from the Outer Continental Shelf and transported directly to such State by means of vessels or by a combination of means including vessels;
(4) Which is designated by the Secretary as a State in which there is a substantial probability of significant impact on or damage to the coastal, marine, or human environment, or a State in which there will be significant changes in the social, governmental, or economic infrastructure, resulting from the exploration, development, and production of oil and gas anywhere on the Outer Continental Shelf; or
(5) In which the Secretary finds that because of such activity there is, or will be, a significant risk of serious damage, due to factors such as prevailing winds and currents, to the marine or coastal environment in the event of any oilspill, blowout, or release of oil or gas from vessels, pipelines, or other transshipment facilities;
(h) Marine environment means the physical, atmospheric, and biological components, conditions, and factors which interactively determine the productivity, state, conditions, and quality of the marine ecosystem, including the waters of the high seas, the contiguous zone, transitional and intertidal areas, salt marshes, and wetlands within the coastal zone and on the Outer Continental Shelf;
(i) Coastal environment means the physical, atmospheric, and biological components, conditions, and factors which interactively determine the productivity, state, conditions, and quality of the terrestrial ecosystem from the shoreline inward to the boundaries of the coastal zone;
(j) Human environment means the physical, social, and economic components, conditions, and factors which interactively determine the state, condition, and quality of living conditions, employment, and health of those affected, directly or indirectly, by activities occurring on the Outer Continental Shelf;
(k) Mineral means oil, gas, and sulphur; it includes sand and gravel and salt used to facilitate the development and production of oil, gas, or sulphur.
(l) Authorized officer means any person authorized by law or by delegation of authority to or within MMS to perform the duties described in this part.
[44 FR 38276, June 29, 1979. Redesignated and amended at 47 FR 47006, 47007, Oct. 22, 1982; 54 FR 2049, Jan. 18, 1989]
§ 256.7
Cross references.
(a) For Minerals Management Service regulations governing exploration, development and production on leases, see 30 CFR parts 250 and 270.
(b) For MMS regulations governing the appeal of an order or decision issued under the regulations in this part, see 30 CFR part 290.
(c) For multiple use conflicts, see the Environmental Protection Agency listing of ocean dumping sites—40 CFR part 228.
(d) For related National Oceanic and Atmospheric Administration programs see:
(1) Marine sanctuary regulations, 15 CFR part 922;
(2) Fishermen's Contingency Fund, 50 CFR part 296;
(3) Coastal Energy Impact Program, 15 CFR part 931;
(e) For Coast Guard regulations on the oil spill liability of vessels and operators, see 33 CFR parts 132, 135, and 136.
(f) For Coast Guard regulations on port access routes, see 33 CFR part 164.
(g) For compliance with the National Environmental Policy Act, see 40 CFR parts 1500 through 1508.
(h) For Department of Transportation regulations on offshore pipeline facilities, see 49 CFR part 195.
(i) For Department of Defense regulations on military activities on offshore areas, see 32 CFR part 252.
[44 FR 38276, June 29, 1979. Redesignated at 47 FR 47006, Oct. 22, 1982, and amended at 54 FR 50617, Dec. 8, 1989; 55 FR 32908, Aug. 13, 1990; 62 FR 27955, May 22, 1997]
§ 256.8
Leasing maps and diagrams.
(a) Any area of the OCS which has been appropriately platted as provided in paragraph (b) of this section, is subject to lease for any mineral not included in a subsisting lease issued under the act or meeting the requirements of subsection (a) of section 6 of the Act. Before any lease is offered or issued an area may be (1) withdrawn from disposition pursuant to section 12(a) of the Act, or (2) designated as an area or part of an area restricted from operation under section 12(d) of the Act.
(b) The MMS shall prepare leasing maps and official protraction diagrams of areas of the OCS. The areas included in each mineral lease shall be in accordance with the appropriate leasing map or official protraction diagram.
§ 256.10
Information to States.
(a) The information covered in this section is prepared by or directly obtained by the Director. Such information is typically not considered to be proprietary or privileged, with the primary exception of specific indications of interest in an area by industry received in response to a Call for Information issued by the Secretary. This information and all other proprietary and privileged information obtained by or under the control of the Minerals Management Service may be released only in accordance with the regulations in 30 CFR parts 250, 251, and 252.
(b) The Director shall prepare an index to OCS information (see 30 CFR 252.5). The index shall list all relevant actual or proposed programs, plans, reports, environmental impact statements, nominations information, environmental study reports, lease sale information and any similar type of relevant information including, modifications, comments and revisions, prepared by or directly obtained by the Director under the act. The index shall be sent on a regular basis to affected States and, upon request, it shall be sent to any affected local government. The public shall be informed of the availability of the index.
(c) Upon request, the Director shall transmit to affected States, local governments or the public, a copy of any information listed in the index which is subject to the control of the MMS in accordance with the requirements and subject to the limitations of the Freedom of Information Act (5 U.S.C. 552) and regulations implementing said Act, and the regulations contained in 43 CFR part 2, except as provided in paragraph (d) of this section.
(d) Upon request, the Director shall provide relative indications of interest in areas as well as any comments filed in response to a Call for Information for a proposed sale. However, no information transmitted shall identify any particular area with the name of any particular party so as not to compromise the competitive position of any participants in the process of indicating interest.
[44 FR 38276, June 29, 1979, as amended at 47 FR 25970, June 16, 1982. Redesignated and amended at 47 FR 47006, 47007, Oct. 22, 1982]
§ 256.11
Helium.
(a) Each lease issued or continued under these regulations shall be subject to a reservation by the United States, under section 12(f) of the Act, of the ownership of and the right to extract helium from all gas produced from the leased area.
(b) In case the United States elects to take the helium, the lessee shall deliver all gas containing helium, or the portion of gas desired, to the United States at any point on the leased area or at an onshore processing facility. Delivery shall be made in the manner required by the United States to such plants or reduction works as the United States may provide.
(c) The extraction of helium shall not cause a reduction in the value of the lessee's gas or any other loss for which he is not reasonably compensated, except for the value of the helium extracted. The United States shall determine the amount of reasonable compensation. The United States shall have the right to erect, maintain and operate on the leased area any and all reduction works and other equipment necessary for the extraction of helium. The extraction of helium shall not cause substantial delays in the delivery of natural gas produced to the purchaser of that gas.
§ 256.12
Supplemental sales.
(a) The Secretary may conduct a supplemental sale in accordance with the provisions of this section.
(b) Supplemental sales shall be governed by the regulations in this part, except § 256.22.
(c) Supplemental sales shall be limited to blocks falling into one or more of the following categories:
(1) Blocks for which bids were rejected during the calendar year preceding the year of the supplemental sale in which they are reoffered or blocks for which bids were rejected in the same calendar year as the supplemental sale in which they are reoffered, except that for the initial supplemental sale only blocks for which bids were rejected after October 1, 1987, may be reoffered. If, after the initial supplemental sale, a supplemental sale is not held annually for any reason, the relevant period for determining blocks eligible for a subsequent supplemental sale may be extended to include rejected bid blocks which were eligible for the supplemental sale not held.
(2) Blocks for which the high bid was forfeited during the calendar year preceding the year of the supplemental sale in which they are reoffered or blocks for which high bids were forfeited in the same calendar year as the supplemental sale in which they are reoffered, except that for the initial supplemental sale only blocks for which high bids were forfeited after October 1, 1987, may be reoffered. If, after the initial supplemental sale, a supplemental sale is not held annually for any reason, the relevant period for determining blocks eligible for a subsequent sale may be extended to include forfeited bid blocks which were eligible for the supplemental sale not held.
(3) Development blocks. Development blocks (including blocks susceptible to drainage) are blocks which are located on the same general geologic structure as an existing lease having a well with indicated hydrocarbons; the reservoir may or may not be interpreted to extend on to the block.
(d) Supplemental sales shall not include blocks in the Central or Western Gulf of Mexico Planning Areas.
(e) The Director may disclose the classification of blocks in supplemental sales as development blocks.
[53 FR 29886, Aug. 9, 1988]

Subpart B—Oil and Gas Leasing Program
§ 256.16
Receipt and consideration of nominations; public notice and participation.
(a) During preparation of a proposed 5-year leasing program, the Secretary shall invite and consider suggestions and relevant information for such program from Governors of affected States, local government, industry, other Federal agencies, including the Attorney General in consultation with the Federal Trade Commission, and all interested parties, including the general public. This request for information shall be issued as a notice in the Federal Register. Local governments wishing to respond to such request shall first submit their responses to the Governor of the State in which the local government is located.
(b) The Secretary shall send letters to the Governors of the affected States requesting them to identify specific laws, goals, and policies which they believe should be considered by the Secretary in connection with the leasing program. The Secretary shall also request from the Secretary of Energy information on regional and national energy markets, on OCS production goals and on transportation networks.
[44 FR 38276, June 29, 1979. Redesignated at 47 FR 47006, Oct. 22, 1982; 47 FR 50684, Nov. 9, 1982]
§ 256.17
Review by State and local governments and other persons.
(a)(1) The Secretary shall prepare a proposed leasing program. At least 60 days prior to publication of the proposed program in the Federal Register, a copy of the draft of the proposed program shall be forwarded to the Governor of each affected State for comment. The Governor may solicit comments from local governments in his or her State which the Governor determines will be affected by the proposed program.
(2) The Secretary shall reply in writing to any comment on the draft of the proposed program from the Governor of an affected State which is received at least 15 days prior to the submission of the proposed program to the Congress and publication in the Federal Register. All such correspondence between the Secretary and Governor of such State shall accompany the proposed program when it is submitted to the Congress.
(b) The proposed leasing program shall be submitted to the Governors of the affected States for review and comment at the time it is submitted to the Congress and the Attorney General and published in the Federal Register. The Governor of an affected State shall, upon request from any local government affected by the program, submit a copy of the proposed program to such local government. Comments and recommendations on any aspect of the proposed program may be submitted by a State or local government or other persons to the Secretary within 90 days after the date of its publication in the Federal Register. Comments and recommendations from local governments shall be submitted first to the Governor of the State in which the local government is located.
(c) At least 60 days prior to approving the final leasing program and any later significant revision, the Secretary shall submit it to the President and the Congress, together with any comments. The Secretary shall indicate in such submission why any specific recommendation of the Attorney General or of a State or local government was not accepted.
[44 FR 38276, June 29, 1979, as amended at 47 FR 25970, June 16, 1982. Redesignated at 47 FR 47006, Oct. 22, 1982; 47 FR 50684, Nov. 9, 1982]
§ 256.19
Periodic consultation with interested parties.
The Secretary shall provide for periodic consultation with State and local governments, existing and potential oil and gas lessees and permittees, and representatives of other individuals or organizations engaged in any activity in or on the OCS, including those involved in fish and shellfish recovery, and recreational activities. This consultation shall take place primarily through appropriate public notice as described in §§ 256.16 and 256.17 and through the OCS Advisory Board and its committees, on a regional and national basis. Meetings of the OCS Advisory Board shall be held on specific issues as required by the Board's charter.
[44 FR 38276, June 29, 1979. Redesignated at 47 FR 47006, Oct. 22, 1982; 47 FR 50684, Nov. 9, 1982]
§ 256.20
Consideration of coastal zone management program.
In the development of the leasing program, consideration shall be given to the coastal zone management program being developed or administered by an affected coastal State under section 305 or 306 of the Coastal Zone Management Act of 1972 as amended, (16 U.S.C. 1454, 1455). Information concerning the relationship between a State's coastal zone management program and OCS oil and gas activity shall be requested from the Governors of the affected coastal States and from the Secretary of Commerce prior to the development of the proposed leasing program at the time information is requested under § 256.16 of this part.
[44 FR 38276, June 29, 1979. Redesignated at 47 FR 47006, Oct. 22, 1982; 47 FR 50684, Nov. 9, 1982]

Subpart C—Reports From Federal Agencies
§ 256.22
General.
For oil and gas lease sales shown in an approved leasing schedule and as the need arises for other mineral leasing, the Director shall prepare a report describing the general geology and potential mineral resources of the area under consideration. The Director may request other interested Federal Agencies to prepare reports describing, to the extent known, any other valuable resources contained within the general area and the potential effect of mineral operations upon the resources or upon the total environment or other uses of the area.
[51 FR 6107, Feb. 20, 1986]

Subpart D—Call for Information and Nominations
§ 256.23
Information on areas.
(a) The Director may receive and consider indications of interest in areas for mineral leasing.
(b) In accordance with an approved program and schedule for the leasing of OCS lands which may contain oil and gas, the Director shall issue Calls for Information and Nominations on areas for leasing of such minerals in specified areas. The Call for Information and Nominations shall be published in the Federal Register and may be published in other publications as desirable. Information on areas shall be addressed to the appropriate regional Minerals Manager of the Minerals Management Service with a copy to any other office which may be specified in the Call. The Director shall also request comments on areas which should receive special concern and analysis. For an oil and gas lease sale Call Area, the Director may request comments concerning geological conditions, including bottom hazards; archaeological sites on the seabed or nearshore; multiple uses of the proposed leasing area, including navigation, recreation, and fisheries; and other socioeconomic, biological, and environmental information.
[47 FR 25970, June 16, 1982. Redesignated at 47 FR 47006, Oct. 22, 1982 and amended at 51 FR 21345, June 12, 1986; 59 FR 53094, Oct. 21, 1994]
§ 256.25
Areas near coastal States.
(a) At the time information is solicited for leasing of areas within 3 geographical miles seaward of the seaward boundary of any coastal State, the Secretary shall provide the Governor of that State information required under section 8(g)(1) of the Act. The Director shall furnish information identifying the areas for leasing as well as all relevant available environmental data for such areas (See 30 CFR 251.14).
(b) After receipt of information on areas within the area described in paragraph (a) of this section, the Secretary shall inform the Governor of those areas that are to be given further consideration for leasing. The Secretary shall enter into consultation with the Governor to determine whether the area may contain oil or gas pools or fields underlying both the OCS and lands subject to the jurisdiction of the State.
(c) After selection for leasing of those tracts which may have oil or gas pools or fields underlying both the OCS and lands under State jurisdiction, the Secretary shall offer the Governor an opportunity to enter into an agreement for the equitable disposition of revenues from such tracts under section 8(g)(2) of the Act.
(d) If no agreement can be reached within 90 days of the Secretary's offer, the tracts may be leased and all revenues deposited in a separate Treasury account pending equitable disposition of the revenues under sections 8(g) (3) and (4) of the Act.
[44 FR 38276, June 29, 1979, as amended at 47 FR 25971, June 16, 1982. Redesignated at 47 FR 47006, Oct. 22, 1982]

Subpart E—Area Identification and Tract Size
§ 256.26
General.
(a) The Director, in consultation with appropriate Federal Agencies, shall recommend to the Secretary areas identified for environmental analysis and consideration for leasing. The Director, on his/her own motion, may include in the recommendation areas in which interest has not been indicated in response to a call. In making a recommendation, the Director shall consider all available environmental information, multiple-use conflicts, resource potential, industry interest and other relevant information. Comments received from States and local governments and interested parties in response to calls for information and nominations shall be considered in making recommendations. For supplemental sales provided for by § 256.12 of this part, the Director's recommendation shall be replaced by a statement describing the results of the Director's consideration of the factors specified above in this section.
(b) The Director shall evaluate fully the potential effect of leasing on the human, marine and coastal environments, and develop measures to mitigate adverse impacts, including lease stipulations. The views and recommendations of Federal agencies, State agencies, local governments, organizations, industries and the general public shall be used as appropriate. The Director may hold public hearings on the environmental analysis after appropriate notice.
(c) In general, the Director shall seek to inform the public as soon as possible of additions or deletions that occur after the identification of areas.
[47 FR 25971, June 16, 1982. Redesignated at 47 FR 47006, Oct. 22, 1982 and amended at 51 FR 21345, June 12, 1986; 53 FR 29886, Aug. 9, 1988]
§ 256.28
Tract size.
(a) A tract selected for oil and gas leasing shall consist of a compact area not exceeding 5,760 acres, unless the authorized officer finds that a larger area is necessary to comprise a reasonable economic production unit.
(b) The tract size for the leasing of other minerals shall be specified in the notice of sale.
[47 FR 25971, June 16, 1982. Redesignated at 47 FR 47006, Oct. 22, 1982]

Subpart F—Lease Sales
§ 256.29
Proposed notice of sale.
(a) The Director shall in consultation with appropriate Federal agencies develop measures, including lease stipulations and conditions, to mitigate adverse impacts on the environments. For oil and gas lease sales, appropriate proposed stipulations and conditions shall be contained or referenced in the proposed notice of lease sale.
(b) A proposed notice of lease sale shall be submitted to the Secretary for approval. All comments and recommendations received and the Director's findings or actions thereon, shall also be forwarded to the Secretary.
(c) Upon approval by the Secretary, the proposed Notice of Sale shall be sent to the Governor of any affected State and a notice of its availability shall be published in the Federal Register.
[44 FR 38276, June 29, 1979, as amended at 47 FR 25971, June 16, 1982. Redesignated at 47 FR 47006, Oct. 22, 1982, and amended at 51 FR 37178, Oct. 20, 1986]
§ 256.31
State comments.
(a) Within 60 days after notice of a proposed lease sale, a Governor of any affected State or any affected local government in such State may submit recommendations to the Secretary regarding the size, timing or location of the proposed lease sale. Prior to submitting recommendations to the Secretary, any affected local government shall forward such recommendation to the Governor.
(b) The Secretary shall accept such recommendations of the Governor and may accept recommendations of any affected local government if he determines, after having provided the opportunity for consultation, that they provide for a reasonable balance between the national interest and the well-being of the citizens of the affected State. A determination of the national interest shall be based on the findings, purposes and policies of the Act.
(c) The Secretary shall communicate to the Governor, in writing, the reasons for his determination to accept or reject such Governor's recommendations, or to implement any alternative means identified in consultation with the Governor to provide for a reasonable balance between the national interest and the well-being of the citizens of the affected State.
§ 256.32
Notice of sale.
(a) Upon approval of the Secretary, the Director shall publish the notice of lease sale in the Federal Register as the official publication, and may publish the notice in other publications. The publication in the Federal Register shall be at least 30 days prior to the date of the sale. The notice shall state the place and time at which bids shall be filed, and the place, date and hour at which bids shall be opened. The notice shall contain or reference a description of the areas to be offered for lease and any stipulations, terms and conditions of the sale.
(b) Tracts shall be offered for lease by competitive sealed bidding under conditions specified in the notice of lease sale and in accordance with all applicable laws and regulations. A suggested format for bidder submissions appears in appendix A of this part.
(c) The notice of lease sale shall contain a reference to the OCS lease form which shall be issued to successful bidders.
(d) With the approval of the Secretary, the Director may defer any part of the payment of the cash bonus according to a schedule announced at the time of the notice of lease sale. Payment shall be made no later than 5 years after the date of the lease sale. The schedule shall contain provisions for guaranteed payment of a deferred bonus.
(e) In order to obtain statistical information to determine which bidding alternatives best accomplish the purposes and policies of the Act, the Director may, until September 18, 1983, require each bidder to submit bids for any OCS area in accordance with more than one of the bidding systems described in section 8(a)(1) of the Act. No more than 10 percent of the tracts offered each year shall contain such a requirement. Leases may be awarded using a bidding alternative selected at random for statistical purposes, if it is otherwise consistent with the purposes and policies of the Act.
[44 FR 38276, June 29, 1979. Redesignated and amended at 47 FR 25971, June 16, 1982. Further redesignated at 47 FR 47006, Oct. 22, 1982]

Subpart G—Issuance of Leases
§ 256.35
Qualifications of lessees.
(a) In accordance with section 8 of the Act, leases shall be awarded only to the highest responsible qualified bidder.
(b) Mineral leases issued pursuant to section 8 of the Act may be held only by: (1) Citizens and nationals of the United States, (2) aliens lawfully admitted for permanent residence in the United States as defined in 8 U.S.C. 1101(a)(20); (3) private, public or municipal corporations organized under the laws of the United States or of any State or of the District of Columbia or territory thereof, or (4) associations of such citizens, nationals, resident aliens, or private, public, or municipal corporations, States, or political subdivisions of States.
(c) MMS may disqualify you from acquiring any new leaseholdings or lease assignments if your operating performance is unacceptable according to 30 CFR 250.135.
[44 FR 38276, June 29, 1979. Redesignated at 47 FR 47006, Oct. 22, 1982, as amended at 64 FR 72795, Dec. 28, 1999]
§ 256.37
Lease term.
(a)(1) All oil and gas leases shall be issued for an initial period of 5 years, or not to exceed 10 years where the authorized officer finds that such longer period is necessary to encourage exploration and development in areas because of unusually deep water or other unusually adverse conditions.
(2) If your oil and gas lease is in water depths between 400 and 800 meters, it will have an initial lease term of 8 years unless MMS establishes a different lease term under paragraph (a)(1) of this section.
(3) For leases issued with an initial term of 8 years, you must begin an exploratory well within the first 5 years of the term to avoid lease cancellation.
(b) An oil and gas lease shall continue after such initial period for as long as oil or gas is produced from the lease in paying quantities, or drilling or well reworking operations as approved by the Secretary are conducted. The term of an oil and gas lease is subject to further extension as provided in § 256.73 of this part.
(c) Sulphur leases shall be issued for a term not to exceed 10 years and so long thereafter as sulphur is produced from the leasehold in paying quantities, or drilling, well reworking, plant construction, or other operations for the production of sulphur, as approved by the Secretary, are conducted thereon.
[44 FR 38276, June 29, 1979. Redesignated at 47 FR 47006, Oct. 22, 1982 and amended at 50 FR 49043, Nov. 29, 1985; 54 FR 2049, Jan. 18, 1989; 61 FR 55889, Oct. 30, 1996]
§ 256.38
Joint bidding provisions.
§ 256.40
Definitions.
The following definitions apply to §§ 256.38 through 256.44 of this part.
(a) Single bid means a bid submitted by one person for an oil and gas lease under section 8(a) of the Act.
(b) Joint bid means a bid submitted by two or more persons for an oil and gas lease under section 8(a) of the Act.
(c) Average daily production is the total of all production in an applicable production period which is chargeable under § 256.43 of this title divided by the exact number of calendar days in the applicable production period.
(d) Barrel means 42 U.S. gallons.
(e) Crude oil means a mixture of liquid hydrocarbons including condensate that exists in natural underground reservoirs and remains liquid at atmospheric pressure after passing through surface separating facilities, but does not include liquid hydrocarbons produced from tar sand, gilsonite, oil shale, or coal.
(f) An economic interest means any right to, or any right dependent upon, production of crude oil, natural gas, or liquefied petroleum products and shall include, but not be limited to, a royalty interest, or overriding royalty interest, whether payable in cash or in kind, a working interest, a net profits interest, a production payment, or a carried interest.
(g) Liquefied petroleum products means natural gas liquid products including the following: ethane, propane, butane, pentane, natural gasoline, and other natural gas products recovered by a process of absorption, adsorption, compression, or refrigeration cycling, or a combination of such processes.
(h) Natural gas means a mixture of hydrocarbons and varying quantities of nonhydrocarbons that exist in the gaseous phase.
(i) Oil and gas lease means an oil and gas lease either offered or issued pursuant to the provisions of the Act.
(j) Owned means:
(1) With respect to crude oil—having either an economic interest in or a power of disposition over the production of crude oil;
(2) With respect to natural gas—having either an economic interest in or a power of disposition over the production of natural gas; and
(3) With respect to liquefied petroleum products—having either an economic interest in or a power of disposition over any liquefied petroleum product at the time of completion of the liquefaction process.
(k) Prior production period means the continuous six month period of January 1 through June 30 preceding November 1 through April 30 for joint bids submitted during the six month bidding period from November 1 through April 30, and means the continuous six month period of July 1 through December 31 preceding May 1 through October 31 for joint bids submitted during the six month bidding period from May 1 through October 31.
(l) Production—(1) Of crude oil means the volume of crude oil produced worldwide from reservoirs during the prior production period. The amount of such crude oil production shall be established by measurement of volumes delivered at the point of custody transfer (e.g., from storage tanks to pipelines, trucks, tankers, or other media for transport to refineries or terminals) with adjustments for:
(i) Net differences between opening and closing inventories, and
(ii) Basic sediment and water;
(2) Of natural gas means the volume of natural gas produced worldwide from natural oil and gas reservoirs during the prior production period, with adjustments, where applicable, to reflect
(i) The volume of gas returned to natural reservoirs; and
(ii) The reduction of volume resulting from the removal of natural gas liquids and nonhydrocarbon gases.
(3) Of liquefied petroleum products means the volume of natural gas liquids produced from reservoir gas and liquefied at surface separators, field facilities, or gas processing plants worldwide during the prior production period; these liquefied petroleum products include the following:
(i) Condensate—natural gas liquids recovered from gas well gas (associated and non-associated) in separators or field facilities;
(ii) Gas plant products—natural gas liquids recovered from natural gas in gas processing plants and from field facilities. Gas plant products shall include the following as classified according to the standards of the Natural Gas Processors Association (NGPA) or the American Society for Testing and Materials (ASTM):
(A) Ethane—C2 H6
(B) Propane—C3 H8
(C) Butane—C4 H 10 including all products covered by NGPA specifications for commercial butane.
(1) Isobutane,
(2) Normal butane,
(3) Other butanes—all butanes not included as isobutane or normal butane;
(D) Butane-Propane Mixtures—All products covered by NGPA specifications for butane-propane mixtures;
(E) Natural Gasoline—A mixture of hydrocarbons extracted from natural gas, which meet vapor pressure, end point, and other specifications for natural gasoline set by NGPA;
(F) Plant Condensate—A natural gas plant product recovered and separated as a liquid at gas inlet separators or scrubbers in processing plants or field facilities; and
(G) Other Natural Gas Plant Products meeting refined product standards (i.e., gasoline, kerosene, distillate, etc.).
(m) Six month bidding period means the six month period of time
(1) From May 1 through October 31; or
(2) From November 1 through April 30, respectively.
[44 FR 38276, June 29, 1979; 44 FR 55380, Sept. 26, 1979. Redesignated at 47 FR 47006, Oct. 22, 1982, as amended at 66 FR 11518, Feb. 23, 2001]
§ 256.41
Joint bidding requirements.
(a) Any person who submits a joint bid for any oil and gas lease during a 6-month bidding period, and who was chargeable for the prior production period with an average daily production in excess of 1.6 million barrels of crude oil, natural gas and liquified petroleum products, shall have filed under oath with the Director, a Statement of Production of crude oil, natural gas and liquified petroleum products, hereinafter referred to as a Statement of Production, no later than 45 days prior to the commencement of the applicable 6-month bidding period of May 1 through October 31, and November 1 through April 30. Statements of Production shall be submitted to the Director, MMS (Attention: Offshore Leasing Management Division), Washington, DC 20240. The Statement of Production shall indicate that the person was chargeable, in accordance with § 256.43 of this part, with an average daily production in excess of 1.6 million barrels of crude oil, natural gas and liquified petroleum products for the prior production period. The Director shall publish semi-annually in the Federal Register a “List of Restricted Joint Bidders” to be effective immediately upon publication and to continue in force and effect until a subsequent list is published. The “List of Restricted Joint Bidders” shall consist of those persons, who in the judgment of the Director, based on information available to him, including, but not limited to, sworn Statements of Production, are chargeable under § 256.43 of this part with an average daily production in excess of 1.6 million barrels of crude oil, natural gas and liquified petroleum products for the prior production period.
(b) When a person is placed on the List of Restricted Joint Bidders the Director shall serve that person either personally or by certified mail, return receipt requested, with a copy of the Director's Order placing that person on the List of Restricted Joint Bidders. Any appeal from that Order or from an adverse effect of that Order shall be made in accordance with the provisions of 43 CFR part 4.
(c) The submission of a Statement of Production or of a detailed Report of Production under § 256.46(g) of this part which misrepresents the chargeable production of the reporting person shall constitute failure to comply with these regulations and any lease awarded in reliance on that Statement or Report of Production may be canceled, pursuant to section 8(o) of the Act and regulations issued thereunder as having been obtained by fraud or misrepresention.
(d) The Secretary may exempt a person from the provisions of §§ 256.41(a), 256.44, 256.46(g) and 256.62(b) of this part if it is found, on the record, after an opportunity for an agency hearing, that lands being offered have extremely high cost exploration and development problems and that exploration and development will not occur on such lands unless the exemption is granted.
[44 FR 38276, June 29, 1979; 44 FR 55380, Sept. 26, 1979, as amended at 45 FR 69174, Oct. 17, 1980; 47 FR 25971, June 16, 1982. Redesignated and amended at 47 FR 47006, 47007, Oct. 22, 1982]
§ 256.43
Chargeability for production.
(a) As used in this section the following definitions shall control:
(1) Person means a natural person or company.
(2) Company means a corporation, a partnership, an association, a joint-stock company, a trust, a fund, or any group of persons whether incorporated or not; it also means any receiver, trustee in bankruptcy, or similar official acting for such a company.
(3) Subsidiary means a company 50 percent or more of whose stock or other interest having power to vote for the election of directors, trustees, or other similar controlling body of the company is directly or indirectly owned, controlled, or held with the power to vote by another company; a subsidiary shall be deemed a subsidiary of the other company owning, controlling, or holding 50 percent or more of the stock or other voting interest.
(4) Security or securities means any note, stock, treasury stock, bond, debenture, evidence of indebtedness, certificate of interest or participation in any profit-sharing agreement, collateral-trust certificate, pre-organization certificate or subscription, transferable share, investment contract, voting-trust certificate, certificate of deposit for a security, fractional undivided interest in oil, gas, or other mineral rights, or, in general, any interest or instrument commonly known as a “security” or any certificate of interest or participation in, temporary or interim certificate for, receipt for, guarantee of, or warrant or right to subscribe to or purchase any of the foregoing.
(b) A person filing a Statement of Production under § 256.41 of this part shall be charged with the following production during the applicable prior production period:
(1) The average daily production in barrels of crude oil, natural gas, and liquefied petroleum products which it owned worldwide;
(2) The average daily production in barrels of crude oil, natural gas, and liquefied petroleum products owned worldwide by every subsidiary of the reporting person;
(3) The average daily production in barrels of crude oil, natural gas, and liquefied petroleum products owned worldwide by any person or persons of which the reporting person is a subsidiary; and
(4) The average daily production in barrels of crude oil, natural gas, and liquefied petroleum products owned worldwide by any subsidiary, other than the reporting person, of any person or persons of which the reporting person is a subsidiary.
(c) A person filing a Statement of Production shall be charged with, in addition to the production chargeable under paragraph (b) of this section, but not in duplication thereof, its proportionate share of the average daily production in barrels of crude oil, natural gas, and liquefied petroleum products owned worldwide by every person:
(1) Which has an interest in the reporting person, and
(2) In which the reporting person has an interest, whether the interest referred to in paragraphs (c) (1) and (2) of this section is by virtue of ownership of securities or other evidence of ownership, or by participation in any contract, agreement, or understanding respecting the control of any person or of any person's production of crude oil, natural gas, or liquefied petroleum products, equal to said interest. As used in paragraph (c) of this section “interest” means an interest of at least 5 percent of the ownership or control of a person.
(d) All measurements of crude oil and liquefied petroleum products under this section shall be at 60 °F.
(e)(1) For purposes of computing production of natural gas under § 256.41 of this part, chargeability under this section, and reporting under § 256.46(g) of this part, 5,626 cubic feet of natural gas at 14.73 pounds per square inch (msl) shall equal one barrel.
(2) For purposes of computing production of liquefied petroleum products under § 256.41 of this part, chargeability under § 256.46(g) of this part, 1.454 barrels of natural gas liquids at 60 °F shall equal one barrel of crude oil.
[44 FR 38276, June 29, 1979; 44 FR 55380, Sept. 26, 1979, as amended at 47 FR 25971, June 16, 1982. Redesignated at 47 FR 47006, 47007, Oct. 22, 1982]
§ 256.44
Bids disqualified.
The following bids for any oil and gas lease shall be disqualified and rejected in their entirety:
(a) A joint bid submitted by 2 or more persons who are on the effective List of Restricted Joint Bidders; or
(b)(1) A joint bid submitted by two or more persons when 1 or more of those persons is chargeable for the prior production period with an average daily production in excess of 1.6 million barrels of crude oil, natural gas and liquified petroleum products and has not filed a Statement of Production as required by § 256.41 of this part for the applicable 6-month bidding period, or
(2) Any of those persons have failed or refused to file a detailed report of production when required to do so under § 256.46(g) of this part, or
(c) A single or joint bid submitted pursuant to an agreement (whether written or oral, formal or informal, entered into or arranged prior to or simultaneously with the submission of such single or joint bid, or prior to or simultaneously with the award of the bid upon the tract) which provides:
(1) For the assignment, transfer, sale, or other conveyance of less than a 100 percent interest in the entire tract on which the bid is submitted, by a person or persons on the List of Restricted Joint Bidders, effective on the date of submission of the bid, to another person or persons on the same List of Restricted Joint Bidders; or
(2) For the assignment, sale, transfer or other conveyance of less than a 100 percent interest in any fractional interest in the entire tract (which fractional interest was originally acquired by the person making the assignment, sale, transfer or other conveyance, under the provisions of the act) by a person or persons on the List of Restricted Joint Bidders, effective on the date of submission of the bid, to another person or persons on the same List of Restricted Joint Bidders; or
(3) For the assignment, sale, transfer, or other conveyance of any interest in a tract by a person or persons not on the List of Restricted Joint Bidders, effective on the date of submission of the bid, to 2 or more persons on the same List of Restricted Joint Bidders; or
(4) For any of the types of conveyances described in paragraphs (c) (1), (2) or (3) of this section where any party to the conveyance is chargeable for the prior production period with an average daily production in excess of 1.6 million barrels of crude oil, natural gas and liquified petroleum products and has not filed a Statement of Production pursuant to § 256.41 of this part for the applicable 6-month bidding period. Assignments expressly required by law, regulation, lease or stipulation to lease shall not disqualify an otherwise qualified bid; or
(d) A bid submitted by or in conjunction with a person who has filed a false, fraudulent or otherwise intentionally false or misleading detailed Report of Production.
[44 FR 38276, June 29, 1979; 44 FR 55380, Sept. 26, 1979, as amended at 45 FR 69175, Oct. 17, 1980; 47 FR 25971, June 16, 1982. Redesignated at 47 FR 47006, Oct. 22, 1982]
§ 256.46
Submission of bids.
(a) A separate sealed bid shall be submitted for each tract unit bid upon as described in the notice of lease sale. A bid may not be submitted for less than an entire tract.
(b) MMS requires a deposit for each bid. The notice of sale will specify the bid deposit amount and method of payment.
(c) If the bidder is an individual a statement of citizenship shall accompany the bid.
(d) If the bidder is an association (including a partnership), the bid shall be accompanied by a certified statement indicating the State in which it is registered and that it is authorized to hold mineral leases on the OCS, or appropriate reference to statements or records previously submitted to an MMS OCS office (including material submitted in compliance with prior regulations).
(e) If the bidder is a corporation, the following information shall be submitted with the bid:
(1) A statement certified by the corporate Secretary or Assistant Secretary over the corporate seal showing the State in which it was incorporated and that it is authorized to hold mineral leases on the OCS, or appropriate reference to statements or records previously submitted to an MMS OCS office (including material submitted in compliance with prior regulations).
(2) Evidence of authority of persons signing to bind the corporation. Such evidence may be in the form of either a certified copy of the minutes of the board of directors or of the bylaws indicating that the person signing has authority to do so; or a certificate to that effect signed by the Secretary or Assistant Secretary of the corporation over the corporate seal, or appropriate reference to statements or records previously submitted to an MMS OCS office (including material submitted in compliance with prior regulations). Bidders are advised to keep their filings current.
(3) The bid shall be executed in conformance with corporate requirements.
(f) Bidders should be aware of the provisions of 18 U.S.C. 1860, prohibiting unlawful combination or intimidation of bidders.
(g) To verify the accuracy of any statement submitted pursuant to § 256.41 of this part, the Director may require the person submitting such information to:
(1) Submit no later than 30 days after receipt of the request by the Director, a detailed Report of Production which shall list, in barrels, the average daily production of crude oil, natural gas and liquefied petroleum products chargeable to the reporting person in accordance with § 256.43 of this part for the prior production period, and
(2) Permit the inspection and copying by an official of the Department of the Interior of such documents, records of production of crude oil, natural gas and liquified petroleum products, analyses and other material as are necessary to demonstrate the accuracy of any statement or information contained in any Report of Production.
(h) No bid for a lease may be submitted if the Secretary finds, after notice and hearing, that the bidder is not meeting due diligence requirements on other OCS leases.
[44 FR 38276, June 29, 1979, as amended at 45 FR 69175, Oct. 17, 1980; 47 FR 25971, June 16, 1982. Redesignated at 47 FR 47006, Oct. 22, 1982, as amended at 64 FR 40767, July 28, 1999]
§ 256.47
Award of leases.
(a) Sealed bids received in response to the notice of lease sale shall be opened at the place, date and hour specified in the notice. The opening of bids is for the sole purpose of publicly announcing and recording the bids received and no bids shall be accepted or rejected at that time.
(b) The United States reserves the right to reject any and all bids received for any tract, regardless of the amount offered.
(c) In the event the highest bids are tie bids, the tie bidders (unless they would be disqualified under § 256.35(b) of this part, or disqualified under § 256.44 of this part if their bids had been joint bids) may file with the Director, within 15 days after notification, an agreement to accept the lease jointly; otherwise all bids shall be rejected.
(d) Pursuant to section 8(c) of the Act, the Attorney General may review the results of the lease sale prior to the acceptance of bids and issuance of leases.
(e)(1) The decision of the authorized officer on bids shall be the final action of the Department, subject only to reconsideration by the Secretary, pursuant to written request, of the rejection of the high bid. The delegation of review authority to the Office of Hearings and Appeals shall not be applicable to decisions on high bids for leases on the Outer Continental Shelf.
(2) The authorized officer must accept or reject the bid within 90 days. The authorized officer may extend the time period for acceptance or rejection of a bid for 15 working days or longer, if circumstances warrant. Any bid not accepted within the prescribed time period, including any extension thereof, is deemed rejected.
(3) Any high bidder whose bid is rejected by the authorized officer may, within 15 days of such rejection, file with the Secretary, with a copy to the authorized officer, a written request for reconsideration accompanied by a statement of reasons. The Secretary shall respond in writing either affirming or reversing the decision of the authorized officer.
(f) Written notice of the authorized officer's action shall be transmitted promptly to those bidders whose deposits have been held. If a bid is accepted, such notice shall transmit three copies of the lease to the successful bidder. As provided in § 218.155, the bidder shall, not later than the 11th business day after receipt of the lease, execute the lease, pay the first-year's rental, and unless deferred, pay the balance of the bonus bid. The bidder must also file a bond as required in § 256.52 of this title. Deposits and any interest accrued shall be refunded on high bids subsequently rejected.
(g) If the successful bidder fails to execute the lease within the prescribed time or otherwise comply with the applicable regulations the deposit shall be forfeited and disposed of as other receipts under the Act.
(h) If, before the lease is executed on behalf of the United States, the land which would be subject to the lease is withdrawn or restricted from leasing, all deposits and any interest due shall be refunded.
(i) If the awarded lease is executed by an agent acting on behalf of the bidder, the lease shall be accompanied by evidence that the bidder authorized the agent to execute the lease. When three copies of the lease are executed and returned to the authorized officer, the lease shall be executed on behalf of the United States, and one fully executed copy shall be transmitted to the successful bidder.
(j) No lease or permit shall be issued for any area within 15 statute miles of the boundaries of the Point Reyes Wilderness in California unless the State of California allows exploration, development or production activities in the adjacent navigable waters of the State under section 11(h) of the Act.
[44 FR 38276, June 29, 1979, as amended at 47 FR 25972, June 16, 1982. Redesignated at 47 FR 47006, Oct. 22, 1982, and amended at 49 FR 8606, Mar. 8, 1984; 49 FR 10056, Mar. 16, 1984; 50 FR 47378, Nov. 18, 1985; 61 FR 34732, July 3, 1996; 62 FR 27955, May 22, 1997]
§ 256.49
Lease form.
Oil and gas leases and leases for sulphur shall be issued on forms approved by the Director. Other mineral leases shall be issued on such forms as may be prescribed by the Secretary.
[47 FR 25972, June 16, 1982. Redesignated at 47 FR 47006, Oct. 22, 1982]
§ 256.50
Dating of leases.
All leases issued under the regulations in this part shall be dated and become effective as of the first day of the month following the date leases are signed on behalf of the lessor. When prior written request is made, a lease may be dated and become effective as of the first day of the month within which it is so signed.
Subpart H—Rentals and Royalties [Reserved]

Subpart I—Bonding
§ 256.52
Bond requirements for an oil and gas or sulphur lease.
This section establishes bond requirements for the lessee of an OCS oil and gas or sulphur lease.
(a) Before MMS will issue a new lease or approve the assignment of an existing lease to you as lessee, you or another record title owner for the lease must:
(1) Maintain with the Regional Director a $50,000 lease bond that guarantees compliance with all the terms and conditions of the lease; or
(2) Maintain a $300,000 areawide bond that guarantees compliance with all the terms and conditions of all your oil and gas and sulphur leases in the area where the lease is located; or
(3) Maintain a lease or areawide bond in the amount required in § 256.53(a) or (b) of this part.
(b) For the purpose of this section, there are three areas. The area offshore the Atlantic Coast is included in the Gulf of Mexico. Areawide bonds issued in the Gulf of Mexico will cover oil and gas or sulphur operations offshore the Atlantic Coast. The three areas are:
(1) The Gulf of Mexico and the area offshore the Atlantic Coast.
(2) The area offshore the Pacific Coast States of California, Oregon, Washington, and Hawaii; and
(3) The area offshore the Coast of Alaska.
(c) The requirement to maintain a lease bond (or substitute security instruments) under paragraph (a)(1) of this section and § 256.53 (a) and (b) is satisfied if your operator provides a lease bond in the required amount that guarantees compliance with all the terms and conditions of the lease. Your operator may use an areawide bond under this paragraph to satisfy your bond obligation.
(d) If a surety makes payment to the United States under a bond or alternative form of security maintained under this section, the surety's remaining liability under the bond or alternative form of security is reduced by the amount of that payment. See paragraph (e) of this section for the requirement to replace the reduced bond coverage.
(e) If the value of your surety bond or alternative security is reduced because of a default, or for any other reason, you must provide additional bond coverage sufficient to meet the security required under this subpart within 6 months, or such shorter period of time as the Regional Director may direct.
(f) You may pledge U.S. Department of the Treasury (Treasury) securities instead of a bond. The Treasury securities you pledge must be negotiable for an amount of cash equal to the value of the bond they replace.
(1) If you pledge Treasury securities under this paragraph (f), you must monitor their value. If their market value falls below the level of bond coverage required under this subpart, you must pledge additional Treasury securities to raise the value of the securities pledged to the required amount.
(2) If you pledge Treasury securities, you must include authority for the Regional Director to sell them and use the proceeds when the Regional Director determines that you fail to satisfy any lease obligation.
(g) You may pledge alternative types of security instruments instead of providing a bond if the Regional Director determines that the alternative security protects the interests of the United States to the same extent as the required bond.
(1) If you pledge an alternative type of security under this paragraph, you must monitor the security's value. If its market value falls below the level of bond coverage required under this subpart, you must pledge additional securities to raise the value of the securities pledged to the required amount.
(2) If you pledge an alternative type of security, you must include authority for the Regional Director to sell the security and use the proceeds when the Regional Director determines that you failed to satisfy any lease obligation.
(h) If you fail to replace a deficient bond or to provide additional bond coverage upon demand, the Regional Director may:
(1) Assess penalties under part 250, subpart N of this chapter;
(2) Suspend production and other operations on your leases in accordance with § 250.110 of this chapter; and
(3) Initiate action to cancel your lease.
[62 FR 27955, May 22, 1997; 64 FR 9066, Feb. 24, 1999, as amended at 66 FR 60150, Dec. 3, 2001]
§ 256.53
Additional bonds.
(a) This paragraph explains what bonds the lessee must provide before lease exploration activities commence.
(1)(i) You must furnish the Regional Director a $200,000 bond that guarantees compliance with all the terms and conditions of the lease by the earliest of:
(A) The date you submit a proposed Exploration Plan (EP) for approval;
(B) The date you submit a request for approval of the assignment of a lease on which an EP has been approved; or
(C) December 8, 1997, for any lease for which an EP has been approved.
(ii) The Regional Director may authorize you to submit the $200,000 lease exploration bond after you submit an EP but before he/she approves drilling activities under the EP.
(iii) You may satisfy the bond requirement of this paragraph (a) by providing a new bond or by increasing the amount of your existing bond.
(2) A $200,000 lease exploration bond pursuant to paragraph (a)(1) of this section need not be submitted and maintained if the lessee either:
(i) Furnishes and maintains an areawide bond in the sum of $1 million issued by a qualified surety and conditioned on compliance with all the terms and conditions of oil and gas and sulphur leases held by the lease on the OCS for the area in which the lessee is situated; or
(ii) Furnishes and maintains a bond pursuant to paragraph (b)(2) of this section.
(b) This paragraph explains what bonds you (the lessee) must provide before lease development and production activities commence.
(1)(i) You must furnish the Regional Director a $500,000 bond that guarantees compliance with all the terms and conditions of the lease by the earliest of:
(A) The date you submit a proposed Development and Production Plan (DPP) or Development Operations Coordination Document (DOCD) for approval;
(B) The date you submit a request for approval of the assignment of a lease on which a DPP or DOCD has been approved; or
(C) December 8, 1997, for any lease for which a DPP or DOCD has been approved.
(ii) The Regional Director may authorize you to submit the $500,000 lease development bond after you submit a DPP or DOCD, but before he/she approves the installation of a platform or the commencement of drilling activities under the DPP or DOCD.
(iii) You may satisfy the bond requirement of this paragraph by providing a new bond or by increasing the amount of your existing bond.
(2) The lessee need not submit and maintain a $500,000 lease development bond pursuant to paragraph (b)(1) of this section if the lessee furnishes and maintains an areawide bond in the sum of $3 million issued by a qualified surety and conditioned on compliance with all the terms and conditions of oil and gas and sulphur leases held by the lessee on the OCS for the area in which the lease is situated.
(c) When a lessee can demonstrate to the satisfaction of the authorized officer that wells and platforms can be abandoned and removed and the drilling and platform sites cleared of obstructions for less than the amount of lease bond coverage required under paragraph (b)(1) of this section, the authorized officer may accept a lease surety bond in an amount less than the prescribed amount but not less than the amount of the cost for well abandonment, platform removal, and site clearance.
(d) The Regional Director may determine that additional security (i.e., security above the amounts prescribed in §§ 256.52(a) and 256.53 (a) and (b) of this part) is necessary to ensure compliance with the obligations under your lease and the regulations in this chapter.
(1) The Regional Director's determination will be based on his/her evaluation of your ability to carry out present and future financial obligations demonstrated by:
(i) Financial capacity substantially in excess of existing and anticipated lease and other obligations, as evidenced by audited financial statements (including auditor's certificate, balance sheet, and profit and loss sheet);
(ii) Projected financial strength significantly in excess of existing and future lease obligations based on the estimated value of your existing OCS lease production and proven reserves of future production;
(iii) Business stability based on 5 years of continuous operation and production of oil and gas or sulphur in the OCS or in the onshore oil and gas industry;
(iv) Reliability in meeting obligations based on:
(A) Credit rating(s); or
(B) Trade references, including names and addresses of other lessees, drilling contractors, and suppliers with whom you have dealt; and
(v) Record of compliance with laws, regulations, and lease terms.
(2) You may satisfy the Regional Director's demand for additional security by increasing the amount of your existing bond or by providing a supplemental bond or bonds.
(e) The Regional Director will determine the amount of supplemental bond required to guarantee compliance. The Regional Director will consider potential underpayment of royalty and cumulative obligations to abandon wells, remove platforms and facilities, and clear the seafloor of obstructions in the Regional Director's case-specific analysis.
(f) If your cumulative potential obligations and liabilities either increase or decrease, the Regional Director may adjust the amount of supplemental bond required.
(1) If the Regional Director proposes an adjustment, the Regional Director will:
(i) Notify you and the surety of any proposed adjustment to the amount of bond required; and
(ii) Give you an opportunity to submit written or oral comment on the adjustment.
(2) If you request a reduction of the amount of supplemental bond required, you must submit evidence to the Regional Director demonstrating that the projected amount of royalties due the Government and the estimated costs of lease abandonment and cleanup are less than the required bond amount. If the Regional Director finds that the evidence you submit is convincing, he/she may reduce the amount of supplemental bond required.
[58 FR 45262, Aug. 27, 1993. Redesignated and amended at 62 FR 27956, May 22, 1997]
§ 256.54
General requirements for bonds.
(a) Any bond or other security that you, as lessee or operator, provide under this part must:
(1) Be payable upon demand to the Regional Director;
(2) Guarantee compliance with all of your obligations under the lease and regulations in this chapter; and
(3) Guarantee compliance with the obligations of all lessees, operating rights owners and operators on the lease.
(b) All bonds and pledges you furnish under this part must be on a form or in a form approved by the Associate Director for Offshore Minerals Management. Surety bonds must be issued by a surety that the Treasury certifies as an acceptable surety on Federal bonds and that is listed in the current Treasury Circular No. 570. You may obtain a copy of the current Treasury Circular No. 570 from the Surety Bond Branch, Financial Management Service, Department of the Treasury, East-West Highway, Hyattsville, MD 20782.
(c) You and a qualified surety must execute your bond. When either party is a corporation, an authorized official for the party must sign the bond and attest to it by an imprint of the corporate seal.
(d) Bonds must be noncancellable, except as provided in § 256.58 of this part. Bonds must continue in full force and effect even though an event occurs that could diminish, terminate, or cancel a surety obligation under State surety law.
(e) Lease bonds must be:
(1) A surety bond;
(2) Treasury securities as provided in § 256.52(f);
(3) Another form of security approved by the Regional Director; or
(4) A combination of these security methods.
(f) You may submit a bond to the Regional Director executed on a form approved under paragraph (b) of this section that you have reproduced or generated by use of a computer. If you do this, and if the document omits terms or conditions contained on the form approved by the Associate Director for Offshore Minerals Management the bond you submit will be deemed to contain the omitted terms and conditions.
[62 FR 27956, May 22, 1997]
§ 256.55
Lapse of bond.
(a) If your surety becomes bankrupt, insolvent, or has its charter or license suspended or revoked, any bond coverage from that surety terminates immediately. In that event, you must promptly provide a new bond in the amount required under §§ 256.52 and 256.53 of this part to the Regional Director and advise the Regional Director of the lapse in your previous bond.
(b) You must notify the Regional Director of any action filed alleging that you, your surety, or guarantor are insolvent or bankrupt. You must notify the Regional Director within 72 hours of learning of such an action. All bonds must require the surety to provide this information to you and directly to MMS.
[62 FR 27957, May 22, 1997]
§ 256.56
Lease-specific abandonment accounts.
(a) The Regional Director may authorize you to establish a lease-specific abandonment account in a federally insured institution in lieu of the bond required under § 256.53(d). The account must provide that, except as provided in paragraph (a)(3) of this section, funds may not be withdrawn without the written approval of the Regional Director.
(1) Funds in a lease-specific abandonment account must be payable upon demand to MMS and pledged to meet the lessee's obligations under § 250.1703 of this chapter.
(2) You must fully fund the lease-specific abandonment account to cover all the costs of lease abandonment and site clearance as estimated by MMS within the timeframe the Regional Director prescribes.
(3) You must provide binding instructions under which the institution managing the account is to purchase Treasury securities pledged to MMS under paragraph (d) of this section.
(b) Any interest paid on funds in a lease-specific abandonment account will be treated as other funds in the account unless the Regional Director authorizes in writing the payment of interest to the party who deposits the funds.
(c) The Regional Director may allow you to pledge Treasury securities that are made payable upon demand to the Regional Director to satisfy your obligation to make payments into a lease-specific abandonment account.
(d) Before the amount of funds in a lease-specific abandonment account equals the maximum insurable amount as determined by the Federal Deposit Insurance Corporation or the Federal Savings and Loan Insurance Corporation, the institution managing the account must use the funds in the account to purchase Treasury securities pledged to MMS under paragraph (c) of this section. The institution managing the lease specific-abandonment account will join with the Regional Director to establish a Federal Reserve Circular 154 account to hold these Treasury securities, unless the Regional Director authorizes the managing institution to retain the pledged Treasury securities in a separate trust account. You may obtain a copy of the current Treasury Circular No. 154 from the Surety Bond Branch, Financial Management Service, Department of the Treasury, East-West Highway, Hyattsville, MD 20782.
(e) The Regional Director may require you to create an overriding royalty or production payment obligation for the benefit of a lease-specific account pledged for the abandonment and clearance of a lease. The required obligation may be associated with oil and gas or sulphur production from a lease other than the lease bonded through the lease-specific abandonment account.
[62 FR 27957, May 22, 1997; 64 FR 9066, Feb. 24, 1999, as amended at 67 FR 35412, May 17, 2002]
§ 256.57
Using a third-party guarantee instead of a bond.
(a) When the Regional Director may accept a third-party guarantee. The Regional Director may accept a third-party guarantee instead of an additional bond under § 256.53(d) if:
(1) The guarantee meets the criteria in paragraph (c) of this section;
(2) The guarantee includes the terms specified in paragraph (d) of this section;
(3) The guarantor's total outstanding and proposed guarantees do not exceed 25 percent of its unencumbered net worth in the United States; and
(4) The guarantor submits an indemnity agreement meeting the criteria in paragraph (e) of this section.
(b) What to do if your guarantor becomes unqualified. If, during the life of your third-party guarantee, your guarantor no longer meets the criteria of paragraphs (a)(3) and (c)(3) of this section, you must:
(1) Notify the Regional Director immediately; and
(2) Cease production until you comply with the bond coverage requirements of this subpart.
(c) Criteria for acceptable guarantees. If you propose to furnish a third party's guarantee, that guarantee must ensure compliance with all lessees' lease obligations, the obligations of all operating rights owners, and the obligations of all operators on the lease. The Regional Director will base acceptance of your third-party guarantee on the following criteria:
(1) The period of time that your third-party guarantor (guarantor) has been in continuous operation as a business entity where:
(i) Continuous operation is the time that your guarantor conducts business immediately before you post the guarantee; and
(ii) Continuous operation excludes periods of interruption in operations that are beyond your guarantor's control and that do not affect your guarantor's likelihood of remaining in business during exploration, development, production, abandonment, and clearance operations on your lease.
(2) Financial information available in the public record or submitted by your guarantor, on your guarantor's own initiative, in sufficient detail to show to the Regional Director's satisfaction that your guarantor is qualified based on:
(i) Your guarantor's current rating for its most recent bond issuance by either Moody's Investor Service or Standard and Poor's Corporation;
(ii) Your guarantor's net worth, taking into account liabilities under its guarantee of compliance with all the terms and conditions of your lease, the regulations in this chapter, and your guarantor's other guarantees;
(iii) Your guarantor's ratio of current assets to current liabilities, taking into account liabilities under its guarantee of compliance with all the terms and conditions of your lease and the regulations in this chapter and your guarantor's other guarantees; and
(iv) Your guarantor's unencumbered fixed assets in the United States.
(3) When the information required by paragraph (c) of this section is not publicly available, your guarantor may submit the information in the following table. Your guarantor must update the information annually within 90 days of the end of the fiscal year or by the date prescribed by the Regional Director.
The guarantor should submit— | that—
(i) Financial statements for the most recently completed fiscal year | Include a report by an independent certified public accountant containing the accountant's audit opinion or review opinion of the statements. The report must be prepared in conformance with generally accepted accounting principles and contain no adverse opinion.
(ii) Financial statements for completed quarters in the current fiscal year | Your guarantor's financial officer certifies to be correct.
(iii) Additional information as requested by the Regional Director | Your guarantor's financial officer certifies to be correct.
(d) Provisions required in all third-party guarantees. Your third-party guarantee must contain each of the following provisions.
(1) If you, your operator, or an operating rights owner fails to comply with any lease term or regulation, your guarantor must either:
(i) Take corrective action; or
(ii) Be liable under the indemnity agreement to provide, within 7 calendar days, sufficient funds for the Regional Director to complete corrective action.
(2) If your guarantor complies with paragraph (d)(1) of this section, this compliance will not reduce its liability.
(3) If your guarantor wishes to terminate the period of liability under its guarantee, it must:
(i) Notify you and the Regional Director at least 90 days before the proposed termination date;
(ii) Obtain the Regional Director's approval for the termination of the period of liability for all or a specified portion of your guarantor's guarantee; and
(iii) Remain liable for all work and workmanship performed during the period that your guarantor's guarantee is in effect.
(4) You must provide a suitable replacement security instrument before the termination of the period of liability under your third-party guarantee.
(e) Required criteria for indemnity agreements. If the Regional Director approves your third-party guarantee, the guarantor must submit an indemnity agreement.
(1) The indemnity agreement must be executed by your guarantor and all persons and parties bound by the agreement.
(2) The indemnity agreement must bind each person and party executing the agreement jointly and severally.
(3) When a person or party bound by the indemnity agreement is a corporate entity, two corporate officers who are authorized to bind the corporation must sign the indemnity agreement.
(4) Your guarantor and the other corporate entities bound by the indemnity agreement must provide the Regional Director copies of:
(i) The authorization of the signatory corporate officials to bind their respective corporations;
(ii) An affidavit certifying that the agreement is valid under all applicable laws; and
(iii) Each corporation's corporate authorization to execute the indemnity agreement.
(5) If your third-party guarantor or another party bound by the indemnity agreement is a partnership, joint venture, or syndicate, the indemnity agreement must:
(i) Bind each partner or party who has a beneficial interest in your guarantor; and
(ii) Provide that, upon demand by the Regional Director under your third-party guarantee, each partner is jointly and severally liable for compliance with all terms and conditions of your lease.
(6) When forfeiture is called for under § 256.59 of this part, the indemnity agreement must provide that your guarantor will either:
(i) Bring your lease into compliance; or
(ii) Provide, within 7 calendar days, sufficient funds to permit the Regional Director to complete corrective action.
(7) The indemnity agreement must contain a confession of judgment. It must provide that, if the Regional Director determines that you, your operator, or an operating rights owner is in default of the lease, the guarantor:
(i) Will not challenge the determination; and
(ii) Will remedy the default.
(8) Each indemnity agreement is deemed to contain all terms and conditions contained in this paragraph (e), even if the guarantor has omitted them.
[62 FR 27957, May 22, 1997]
§ 256.58
Termination of the period of liability and cancellation of a bond.
This section defines the terms and conditions under which MMS will terminate the period of liability of a bond or cancel a bond. Terminating the period of liability of a bond ends the period during which obligations continue to accrue but does not relieve the surety of the responsibility for obligations that accrued during the period of liability. Canceling a bond relieves the surety of all liability. The liabilities that accrue during a period of liability include obligations that started to accrue prior to the beginning of the period of liability and had not been met and obligations that begin accruing during the period of liability.
(a) When the surety under your bond requests termination:
(1) The Regional Director will terminate the period of liability under your bond within 90 days after MMS receives the request; and
(2) If you intend to continue operations, or have not met all end of lease obligations, you must provide a replacement bond of an equivalent amount.
(b) If you provide a replacement bond, the Regional Director will cancel your previous bond and the surety that provided your previous bond will not retain any liability, provided that:
(1) The new bond is equal to or greater than the bond that was terminated, or you provide an alternative form of security, and the Regional Director determines that the alternative form of security provides a level of security equal to or greater than that provided for by the bond that was terminated;
(2) For a base bond submitted under § 256.52(a) or under § 256.53(a) or (b), the surety issuing the new bond agrees to assume all outstanding liabilities that accrued during the period of liability that was terminated; and
(3) For supplemental bonds submitted under § 256.53(d), the surety issuing the new supplemental bond agrees to assume that portion of the outstanding liabilities that accrued during the period of liability which was terminated and that the Regional Director determines may exceed the coverage of the base bond, and of which the Regional Director notifies the provider of the bond.
(c) This paragraph applies if the period of liability is terminated for a bond but the bond is not replaced by a bond of an equivalent amount. The surety that provided your terminated bond will continue to be responsible for accrued obligations:
(1) Until the obligations are satisfied; and
(2) For additional periods of time in accordance with paragraph (d) of this section.
(d) When your lease expires or is terminated, the surety that issued a bond will continue to be responsible, and the Regional Director will retain other forms of security as shown in the following table:
For the following type of bond | The period of liability will end | Your bond will be cancelled . . .
(1) Base bonds submitted under § 256.52(a), § 256.53(a), or (b) | When the Regional Director determines that you have met all of your obligations under the lease | Seven years after the termination of the lease, 6 years after completion of all bonded obligations, or at the conclusion of any appeals or litigation related to your bonded obligation, whichever is the latest. The Regional Director will reduce the amount of your bond or return a portion of your security if the Regional Director determines that you need less than the full amount of the base bond to meet any possible future problems.
(2) Supplemental bonds submitted under § 256.53(d) | When the Regional Director determines that you have met all your obligations covered by the supplemental bond | When you meet your bonded obligations, unless the Regional Director: (i) Determines that the future potential liability resulting from any undetected problems is greater than the amount of the base bond; and (ii) Notifies the provider of the bond that the Regional Director will wait 7 years before cancelling all or a part of the bond (or longer period as necessary to complete any appeals or judicial litigation related to your bonding obligation).
(e) For all bonds, the Regional Director may reinstate your bond as if no cancellation or release had occurred if:
(1) A person makes a payment under the lease and the payment is rescinded or must be repaid by the recipient because the person making the payment is insolvent, bankrupt, subject to reorganization, or placed in receivership; or
(2) The responsible party represents to MMS that it has discharged its obligations under the lease, and the representation was materially false when the bond was canceled or released.
[66 FR 60150, Dec. 3, 2001]
§ 256.59
Forfeiture of bonds and/or other securities.
This section explains how a bond or other security may be forfeited.
(a) The Regional Director will call for forfeiture of all or part of the bond, other form of security, or guarantee you provide under this part if:
(1) You (the party who provided the bond) refuse, or the Regional Director determines that you are unable, to comply with any term or condition of your lease; or
(2) You default under one of the conditions under which the Regional Director accepts your bond, third-party guarantee, and/or other form of security.
(b) The Regional Director may pursue forfeiture of your bond without first making demands for performance against any lessee, operating rights owner, or other person authorized to perform lease obligations.
(c) The Regional Director will:
(1) Notify you, the surety on your bond or other form of security, and any third-party guarantor, of his/her determination to call for forfeiture of the bond, security, or guarantee under this section.
(i) This notice will be in writing and will provide the reasons for the forfeiture and the amount to be forfeited.
(ii) The Regional Director must base the amount he/she determines is forfeited upon his/her estimate of the total cost of corrective action to bring your lease into compliance.
(2) Advise you, your third-party guarantor, and any surety, that you, your guarantor, and any surety may avoid forfeiture if, within 5 working days:
(i) You agree to, and demonstrate that you will, bring your lease into compliance within the timeframe that the Regional Director prescribes;
(ii) Your third-party guarantor agrees to, and demonstrates that it will, complete the corrective action to bring your lease into compliance within the timeframe that the Regional Director prescribes; or
(iii) Your surety agrees to, and demonstrates that it will, bring your lease into compliance within the timeframe that the Regional Director prescribes, even if the cost of compliance exceeds the face amount of the bond or other surety instrument.
(d) If the Regional Director finds you are in default, he/she may cause the forfeiture of any bonds and other security deposited as your guarantee of compliance with the terms and conditions of your lease and the regulations in this chapter.
(e) If the Regional Director determines that your bond and/or other security is forfeited, the Regional Director will:
(1) Collect the forfeited amount; and
(2) Use the funds collected to bring your leases into compliance and to correct any default.
(f) If the amount the Regional Director collects under your bond and other security is insufficient to pay the full cost of corrective actions he/she may:
(1) Take or direct action to obtain full compliance with your lease and the regulations in this chapter; and
(2) Recover from you, any co-lessee, operating rights owner, and/or any third-party guarantor responsible under this subpart all costs in excess of the amount he/she collects under your forfeited bond and other security.
(g) The amount that the Regional Director collects under your forfeited bond and other security may exceed the costs of taking the corrective actions required to obtain full compliance with the terms and conditions of your lease and the regulations in this chapter. In this case, the Regional Director will return the excess funds to the party from whom they were collected.
[62 FR 27958, May 22, 1997]

Subpart J—Assignments, Transfers, and Extensions
§ 256.62
Assignment of lease or interest in lease.
This section explains how to assign record title and other interests in OCS oil and gas or sulphur leases.
(a) MMS may approve the assignment to you of the ownership of the record title to a lease or any undivided interest in a lease, or an officially designated subdivision of a lease, only if:
(1) You qualify to hold a lease under § 256.35(b);
(2) You provide the bond coverage required under subpart I of this part; and
(3) The Regional Director approves the assignment.
(b) An assignment shall be void if it is made pursuant to any prelease agreement described in § 256.44(c) of this part that would cause a bid to be disqualified.
(c) Any approved assignment shall be deemed to be effective on the first day of the lease month following its filing in the appropriate office of the MMS, unless at the request of the parties, an earlier date is specified in the approval.
(d) You, as assignor, are liable for all obligations that accrue under your lease before the date that the Regional Director approves your request for assignment of the record title in the lease. The Regional Director's approval of the assignment does not relieve you of accrued lease obligations that your assignee, or a subsequent assignee, fails to perform.
(e) Your assignee and each subsequent assignee are liable for all obligations that accrue under the lease after the date that the Regional Director approves the governing assignment. They must:
(1) Comply with all the terms and conditions of the lease and all regulations issued under the Act; and
(2) Remedy all existing environmental problems on the tract, properly abandon all wells, and reclaim the lease site in accordance with part 250, subpart Q.
(f) If your assignee, or a subsequent assignee, fails to perform any obligation under the lease or the regulations in this chapter, the Regional Director may require you to bring the lease into compliance to the extent that the obligation accrued before the Regional Director approved the assignment of your interest in the lease.
[44 FR 38276, June 29, 1979. Redesignated at 47 FR 47006, Oct. 22, 1982, and amended at 58 FR 45262, Aug. 27, 1993; 62 FR 27959, May 22, 1997; 67 FR 35412, May 17, 2002]
§ 256.63
Service fees.
(a) The table in this paragraph (a) shows the fees that you must pay to MMS for the services listed. The fees will be adjusted periodically according to the Implicit Price Deflator for Gross Domestic Product by publication of a document in the Federal Register. If a significant adjustment is needed to arrive at the new actual cost for any reason other than inflation, then a proposed rule containing the new fees will be published in the Federal Register for comment.
Service Fee Table
[Effective September 26, 2005]
Service | Fee amount | 30 CFR citation
(1) Record Title/Operating Rights (Transfer) | $170 | § 256.64
(2) Non-required Document Filing | 25 | § 256.64
(b) Once a fee is paid, it is nonrefundable, even if an application or other request is withdrawn. If your application is returned to you as incomplete, you are not required to submit a new fee with the amended application.
[70 FR 49876, Aug. 25, 2005]
§ 256.64
How to file transfers.
This section explains how to file instruments with MMS that create and/or transfer interests in OCS oil and gas or sulphur leases.
(a) You must submit to the Regional Director for approval all instruments that create or transfer ownership of a lease interest.
(1) You must submit two copies of the instruments that create or transfer an interest. Each instrument that creates or transfers an interest must describe by officially designated subdivision the interest you propose to create or transfer.
(2) You must submit your proposal to create or transfer an interest, or create or transfer separate operating rights, subleases, and record title interests within 90 days of the last date that a party executes the transfer agreement.
(3) The transferee must meet the citizenship and other qualification criteria specified in § 256.35 of this part. When you submit an instrument to create or transfer an interest as an association, you must include a statement signed by the transferee about the transferee's citizenship and qualifications to own a lease.
(4) Your instrument to create or transfer an interest must contain all of the terms and conditions to which you and the other parties agree.
(5) You do not gain a release of any nonmonetary obligation under your lease or the regulations in this chapter by creating a sublease or transferring operating rights.
(6) You do not gain a release from any accrued obligation under your lease or the regulations in this chapter by assigning your record title interest in the lease.
(7) You may create or transfer carried working interests, overriding royalty interests, or payments out of production without obtaining the Regional Director's approval. However, you must file instruments creating or transferring carried working interests, overriding royalty interests, or payments out of production with the Regional Director for record purposes.
(8) You must pay the service fee listed in § 256.63 of this subpart with your application for approval of any instrument of transfer you are required to file (Record Title/Operating Rights (Transfer) Fee). Where multiple transfers of interest are included in a single instrument, a separate fee applies to each individual transfer of interest. For any document you are not required to file by these regulations but which you submit for record purposes per lease affected, you must also pay the service fee listed in § 256.63 (Non-required Document Filing Fee). Such documents may be rejected at the discretion of the authorized officer.
(9) Notwithstanding the provisions of paragraph (a)(8) of this section, the requirements to pay a filing fee in connection with any application for approval of any instrument of transfer and to pay a fee in connection with documents not required to be filed are suspended until January 3, 2006.
(b) An attorney in fact, in behalf of the holder of a lease, operating rights or sublease, shall furnish evidence of authority to execute the assignment or application for approval and the statement required by § 256.46 of this part.
(c) When you request approval for an assignment that assigns all your record title interest in a lease or that creates a segregated lease, your assignee must furnish a bond in the amount prescribed in §§ 256.52 and 256.53 of this part.
(d) When you request approval for an assignment that assigns less than all the record title of a lease and that does not create a separate lease, the assignee may, with the surety's consent, become a joint principal on the surety instrument that guarantees compliance with all the terms and conditions of the lease.
(e) An heir or devisee of a deceased holder of a lease, or any interest therein, shall be recognized as the lawful successor to such lease or interest, if evidence of status as an heir or devisee is furnished in the form of:
(1) A certified copy of an appropriate order or decree of the court having jurisdiction of the distribution of the estate or,
(2) If no court action is necessary, the statements of two disinterested parties having knowledge of the facts or a certified copy of the will.
(f) In addition to the requirements of paragraph (d) of this section, the heirs or devisees shall file statements that they are the persons named as successors to the estate with evidence of their qualifications as provided in § 256.46 of this part.
(g) In the event an heir or devisee is unable to qualify to hold the lease or interest, the heir or devisee shall be recognized as the lawful successor of the deceased and be entitled to hold the lease for a period of not to exceed 2 years from the date of death of the predecessor in interest.
(h) Your heirs, executors, administrators, successors, and assigns are bound to comply with each obligation under any lease and under the regulations in this chapter.
(1) You are jointly and severally liable for the performance of each nonmonetary obligation under the lease and under the regulations in this chapter with each prior lessee and with each operating rights owner holding an interest at the time the obligation accrued, unless this chapter provides otherwise.
(2) Sublessees and operating rights owners are jointly and severally liable for the performance of each nonmonetary obligation under the lease and under the regulations in this chapter to the extent that:
(i) The obligation relates to the area embraced by the sublease;
(ii) Those owners held their respective interest at the time the obligation accrued; and
(iii) This chapter does not provide otherwise.
(i) Where the proposed assignment or transfer is by a person who, at the time of acquisition of an interest in the lease, was on the List of Restricted Joint Bidders, and that assignment or transfer is of less than the entire interest of the assignor or transferor, to a person or persons on the same List of Restricted Joint Bidders, the assignor or transferor shall file a copy, prior to approval of the assignment, of all agreements applicable to the acquisition of that lease or a fractional interest.
[44 FR 38276, June 29, 1979. Redesignated at 47 FR 47006, Oct. 22, 1982, as amended at 62 FR 27959, May 22, 1997; 62 FR 39775, July 24, 1997; 70 FR 49877, Aug. 25, 2005; 70 FR 61893, Oct. 27, 2005]
§ 256.65
Attorney General review.
Prior to the approval of an assignment or transfer, the Secretary shall consult with and give due consideration to the views of the Attorney General. The Secretary may act on an assignment or transfer if the Attorney General has not responded to the request for consultation within 30 days of said request.
§ 256.67
Separate filings for assignments.
A separate instrument of assignment shall be filed for each lease. When transfers to the same person, association or corporation, involving more than one lease are filed at the same time for approval, one request for approval and one showing as to the qualifications of the assignee shall be sufficient.
§ 256.68
Effect of assignment of a particular tract.
(a) When an assignment is made of all the record title to a portion of the acreage in a lease, the assigned and retained portions become segregated into separate and distinct leases. In such a case, the assignee becomes a lessee of the Government as to the segregated tract that is the subject of assignment, and is bound by the terms of the lease as though the lease had been obtained from the United States in the assignee's own name, and the assignment, after its approval, shall be the basis of a new record. Royalty, minimum royalty and rental provisions of the original lease shall apply separately to each segregated portion.
(b) For assignments of a portion of an oil and gas lease approved after the effective date of ths section, each segregated lease shall continue in full force and effect for the primary term of the original lease and so long thereafter as oil or gas is produced from that segregated portion of the leased area in paying quantities or drillng or well reworking operations as approved by the Secretary are conducted.
(c) For those assignments approved prior to the effective date of this section, each segregated lease shall continue in full force and effect for the primary term of the original lease and so long thereafter as oil and gas may be produced from the original leased area in paying quantities or drilling or well reworking operations, as approved by the Secretary, are conducted.
§ 256.70
Extension of lease by drilling or well reworking operations.
The term of a lease shall be extended beyond the primary term so long as drilling or well reworking operations are approved by the Secretary according to the conditions set forth in 30 CFR 250.180.
[44 FR 38276, June 29, 1979, as amended at 55 FR 32908, Aug. 13, 1990; 64 FR 9066, Feb. 24, 1999; 64 FR 72795, Dec. 28, 1999]
§ 256.71
Directional drilling.
In accordance with an approved exploration plan or development and production plan, a lease may be maintained in force by directional wells drilled under the leased area from surface locations on adjacent or adjoining land not covered by the lease. In such circumstances, drilling shall be considered to have commenced on the leased area when drilling is commenced on the adjacent or adjoining land for the purpose of directional drilling under the leased area through any directional well surfaced on adjacent or adjoining land. Production, drillling or reworking of any such directional well shall be considered production or drilling or reworking operations on the leased area for all purposes of the lease.
§ 256.72
Compensatory payments as production.
If an oil and gas lessee makes compensatory payments and if the lease is not being maintained in force by other production of oil or gas in paying quantities or by other approved drilling or reworking operations, such payments shall be considered as the equivalent of production in paying quantities for all purposes of the lease.
[44 FR 38276, June 29, 1979. Redesignated at 47 FR 47006, Oct. 22, 1982, and amended at 54 FR 50617, Dec. 8, 1989]
§ 256.73
Effect of suspensions on lease term.
(a) A suspension may extend the term of a lease (see 30 CFR 250.171) with the extension being the length of time the suspension is in effect except as provided in paragraph (b) of this section.
(b) A Directed Suspension does not extend the lease term when the Regional Supervisor directs a suspension because of:
(1) Gross negligence; or (2) A willful violation of a provision of the lease or governing regulations.
(c) MMS may issue suspensions for a period of up to 5 years per suspension. The Regional Supervisor will set the length of the suspension based on the conditions of the individual case involved. MMS may grant consecutive suspensions. For more information on suspension of operations or production refer to the section under the heading “Suspensions” in 30 CFR part 250, subpart A.
[64 FR 72795, Dec. 28, 1999]

Subpart K—Termination of Leases
§ 256.76
Relinquishment of leases or parts of leases.
A lease or any officially designated subdivision thereof may be surrendered by the record title holder by filing a written relinquishment, in triplicate, with the appropriate OCS office of the MMS. No filing fee is required. A relinquishment shall take effect on the date it is filed subject to the continued obligation of the lessee and the surety to make all payments due, including any accrued rentals, royalties and deferred bonuses and to abandon all wells and condition or remove all platforms and other facilities on the land to be relinquished to the satisfaction of the Director.
§ 256.77
Cancellation of leases.
(a) Any nonproducing lease issued under the act may be cancelled by the authorized officer whenever the lessee fails to comply with any provision of the act or lease or applicable regulations, if such failure to comply continues for 30 days after mailing of notice by registered or certified letter to the lease owner at the owner's record post office address. Any such cancellation is subject to judicial review as provided in section 23(b) of the Act.
(b) Producing leases issued under the Act may be cancelled by the Secretary whenever the lessee fails to comply with any provision of the Act, applicable regulations or the lease only after judicial proceedings as prescribed by section 5(d) of the Act.
(c) Any lease issued under the Act, whether producing or not, shall be canceled by the authorized officer upon proof that it was obtained by fraud or misrepresentation, and after notice and opportunity to be heard has been afforded to the lessee.
(d) Pursuant to section 5(a) of the Act, the Secretary may cancel a lease when:
(1) Continued activity pursuant to such lease would probably cause serious harm or damage to life, property, any mineral, national security or defense, or to the marine, coastal or human environment;
(2) The threat of harm or damage will not disappear or decrease to an acceptable extent within a reasonable period of time; and
(3) The advantages of cancellation outweigh the advantages of continuing such lease or permit in force. Procedures and conditions contained in 30 CFR 250.182 shall apply as appropriate.
[44 FR 38276, June 29, 1979; 44 FR 55380, Sept. 26, 1979. Redesignated at 47 FR 47006, Oct. 22, 1982; 64 FR 13343, Mar. 18, 1999; 64 FR 72795, Dec. 28, 1999]

Subpart L—Section 6 Leases
§ 256.79
Effect of regulations on lease.
(a) All regulations in this part, insofar as they are applicable, shall supersede the provisions of any lease which is maintained under section 6(a) of the Act. However, the provisions of a lease relating to area, minerals, rentals, royalties (subject to sections 6(a) (8) and (9) of the Act), and term (subject to section 6(a)(10) of the Act and, as to sulfur, subject to section 6(b)(2) of the Act) shall continue in effect, and, in the event of any conflict or inconsistency, shall take precedence over these regulations.
(b) A lease maintained under section 6(a) of the Act shall also be subject to all operating and conservation regulations applicable to the OCS. In addition, the regulations relating to geophysical and geological exploratory operations and to pipeline rights-of-way are applicable, to the extent that those regulations are not contrary to or inconsistent with the lease provisions relating to area, the minerals, rentals, royalties and term. The lessee shall comply with any provision of the lease as validated, the subject matter of which is not covered in the regulations in this part.
[44 FR 38276, June 29, 1979; 44 FR 55380, Sept. 26, 1979. Redesignated at 47 FR 47006, Oct. 22, 1982]
§ 256.80
Leases of other minerals.
The existence of a lease that meets the requirements of section 6(a) of the Act shall not preclude the issuance of other leases of the same area for deposits of other minerals. However, no other lease of minerals shall authorize or permit the lessee thereunder unreasonably to interfere with or endanger operations under the existing lease. No sulphur leases shall be granted by the United States on any area while such area is included in a lease covering sulphur under section 6(b) of the Act.

Subpart M—Studies
§ 256.82
Environmental studies.
(a) The Director shall conduct a study of any area or region included in any lease sale in order to establish information needed for assessment and management of impacts on the human, marine and coastal environments which may be affected by OCS oil and gas activities in such area or region. Any study shall, to the extent practicable, be designed to predict environmental impacts of pollutants introduced into the environments and of the impacts of offshore activities on the seabed and affected coastal areas.
(b) Studies shall be planned and carried out in cooperation with the affected States and interested parties and, to the extent possible, shall not duplicate studies done under other laws. Where appropriate, the Director shall, to the maximum extent practicable, enter into agreements with the National Oceanic and Atmospheric Administration in executing the environmental studies responsibilities. By agreement, the Director may also utilize services, personnel or facilities of any Federal, State or local government agency in the conduct of such study.
(c) Any study of an area or region required by paragraph (a) of this section for a lease sale shall be commenced not later than six months prior to holding a lease sale for that area. The Director may utilize information collected in any prior study. The Director may initiate studies for areas or regions not identified in the leasing program.
(d) After the leasing and developing of any area or region, the Director shall conduct such studies as are deemed necessary to establish additional information and shall monitor the human, marine and coastal environments of such area or region in a manner designed to provide information which can be compared with the results of studies conducted prior to OCS oil and gas development. This shall be done to identify any significant changes in the quality and productivity of such environments, to establish trends in the areas studies, and to design experiments identifying the causes of such changes. Findings from such studies shall be used to recommend modifications in practices which are employed to mitigate the effects of OCS activities and to enhance the data/information base for predicting impacts which might result from a single lease sale or cumulative OCS activities.
(e) Information available or collected by the studies program shall, to the extent practicable, be provided in a form and in a timeframe that can be used in the decision-making process associated with a specific leasing action or with longer term OCS minerals management responsibilities.
Pt. 256, App. A

Appendix A to Part 256—Oil and Gas Cash Bonus Bid
The following bid is submitted for an oil and gas lease on the area of the Outer Continental Shelf specified below:
Tract No.* | Total amount bid | Amount per acre (or per hectare) | Amount of cash submitted with bid
*Or, if tract numbers are not used, Protraction Diagram or Leasing Map and block number.
Bidder qualification No. | Proportionate interest of company(s) submitting bid | Name and address of bidding company
__ Misc. No. | |
____________,
Authorized signatory's name and title.
[47 FR 25972, June 16, 1982. Redesignated at 47 FR 47006, Oct. 22, 1982]
Pt. 259

PART 259—MINERAL LEASING: DEFINITIONS
Sec.
259.001
Purpose and scope.
259.002
Definitions.

Authority:
Pub. L. 83-212, 67 Stat. 462, 43 U.S.C. 1331 et seq., as amended by Pub. L. 95-372, 92 Stat. 629.
§ 259.001
Purpose and scope.
The purpose of this part 259 is to define various terms appearing in parts 260, 261 and 262 of this chapter.
[48 FR 1182, Jan. 11, 1983]
§ 259.002
Definitions.
For purposes of parts 260, 261, and 262 of this chapter:
Area or region means the geographic area or region over which the MMS designated official has jurisdiction, unless the context in which those words are used indicates that a different meaning is intended.
Designated official means a representative of DOI subject to the direction and supervisory authority of the Director, MMS, and the appropriate Regional Manager of the MMS authorized and empowered to supervise and direct all oil and gas operations and to perform other duties prescribed in 30 CFR part 250 (offshore).
Director means Director, MMS, DOI.
DOI means the Department of the Interior, including the Secretary of the Interior, or his or her delegate.
Federal lease means an agreement which, for any consideration, including, but not limited to, bonuses, rents or royalties conferred, and convenants to be observed, authorizes a person to explore for, or develop, or produce (or to do any or all of these) oil and gas, coal, oil shale, tar sands, and goethermal resources on lands or interests in lands under Federal jurisdiction.
Gas means natural gas as defined by the Federal Energy Regulatory Commission.
MMS means Minerals Management Service.
OCS means the Outer Continental Shelf, which includes all submerged lands (1) that lie seaward outside of the area of lands beneath navigable waters as defined in the Submerged Lands Act (Pub. L. 31-35, 67 Stat. 29, (43 U.S.C. 1301)) and (2) of which the subsoil and seabed appertain to the United States are subject to its jurisdiction and control.
OCSLA means the Outer Continental Shelf Lands Act, as amended (Act of August 7, 1953, Ch. 345, 67 Stat. 462, 43 U.S.C. 1331 et seq., as amended by Pub. L. 95-372, 92 Stat. 629).
Oil means a mixture of hydrocarbons that exists in a liquid or gaseous phase in an underground reservoir and which remains or becomes liquid at atmospheric pressure after passing through surface separating facilities, including condensate recovered by means other than a manufacturing process.
[48 FR 1182, Jan. 11, 1983]
Pt. 260

PART 260—OUTER CONTINENTAL SHELF OIL AND GAS LEASING

Subpart A—General Provisions
Sec.
260.1
What is the purpose of this part?
260.2
What definitions apply to this part?
260.3
What is MMS's authority to collect information?

Subpart B—Bidding Systems

General Provisions
260.101
What is the purpose of this subpart?
260.102
What definitions apply to this subpart?
260.110
What bidding systems may MMS use?
260.111
What conditions apply to the bidding systems that MMS uses?

Eligible Leases
260.112
How do royalty suspension volumes apply to eligible leases?
260.113
When does an eligible lease qualify for a royalty suspension volume?
260.114
How does MMS assign and monitor royalty suspension volumes for eligible leases?
260.115
How long will a royalty suspension volume for an eligible lease be effective?
260.116
How do I measure natural gas production on my eligible lease?
260.117
What other provisions apply to royalty suspension volumes for eligible leases?

Royalty Suspension (RS) Leases
260.120
How does royalty suspension apply to leases issued in a sale held after November 2000?
260.121
When does a lease issued in a sale held after November 2000 get a royalty suspension?
260.122
How long will a royalty suspension volume be effective for a lease issued in a sale held after November 2000?
260.123
How do I measure natural gas production for a lease issued in a sale held after November 2000?
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 an eligible or pre-Act lease?

Bidding System Selection Criteria
260.130
What criteria does MMS use for selecting bidding systems and bidding system components?
Subpart C [Reserved]

Subpart D—Joint Bidding
260.301
What is the purpose of this subpart?
260.302
What definitions apply to this subpart?
260.303
What are the joint bidding requirements?

Authority:
43 U.S.C. 1331 et seq.

Source:
66 FR 11518, Feb. 23, 2001, unless otherwise noted.

Subpart A—General Provisions
§ 260.1
What is the purpose of this part?
Part 260 implements the Outer Continental Shelf Lands Act (OCSLA), 43 U.S.C. 1331 et seq., as amended, by providing regulations to foster competition including, but not limited to:
(a) Implementing alternative bidding systems;
(b) Prohibiting joint bidding for development rights by certain types of joint ventures; and
(c) Establishing diligence requirements for Federal OCS leases.
§ 260.2
What definitions apply to this part?
OCS lease means a Federal lease for oil and gas issued under the OCSLA.
OCSLA means the Outer Continental Shelf Lands Act, (43 U.S.C. 1331 et seq.), as amended.
Person includes, in addition to a natural person, an association, a State, or a private, public, or municipal corporation.
We means the Minerals Management Service (MMS).
You means the lessee or operating rights holder.
§ 260.3
What is MMS's authority to collect information?
The Paperwork Reduction Act of 1995 (PRA) requires us to inform you that we may not conduct or sponsor and you are not required to respond to a collection of information unless it displays a currently valid OMB control number. OMB approved the information collection requirements in part 260 under 44 U.S.C. 3501 et seq. and assigned OMB control number 1010-0143. The PRA also requires us to inform you of the following:
(a) We use the information collected under §§ 260.114(a)(2), (c)(1) and 260.124 (a)(2):
(1) To make decisions on requests for reconsideration of our assignment of a lease that has a qualifying well to an existing field or designate a new field under §§ 260.114(a) and 260.124(a), and
(2) To ensure that the royalty suspension volume is properly allocated among constituent leases in a field under § 260.117.
(b) Respondents are Federal OCS oil and gas lessees and operating rights holders. Responses are required to obtain or retain a benefit. We will protect proprietary information under applicable law and part 250 of this chapter.
(c) You may 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, Minerals Management Service, Mail Stop 4230, 1849 C Street, NW., Washington, DC 20240.

Subpart B—Bidding Systems

General Provisions
§ 260.101
What is the purpose of this subpart?
This subpart establishes the bidding systems that we may use to offer and sell Federal leases for the exploration, development, and production of oil and gas resources located on the OCS.
§ 260.102
What definitions apply to this subpart?
Act means the Outer Continental Shelf Deep Water Royalty Relief Act, Pub. L. 104-58, 43 U.S.C. 1337(3).
Eligible lease means a lease that:
(1) Is issued as part of an OCS lease sale held after November 28, 1995, and before November 28, 2000;
(2) Is located in the Gulf of Mexico in water depths of 200 meters or deeper;
(3) Lies wholly west of 87 degrees, 30 minutes West longitude; and
(4) Is offered subject to a royalty suspension volume.
Field means an area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same general geological structural feature and/or stratigraphic trapping condition. Two or more reservoirs may be in a field, separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both.
Highest responsible qualified bidder means a person who has met the appropriate requirements of 30 CFR part 256, subpart G of this title, and has submitted a bid higher than any other bids by qualified bidders on the same tract.
Highest royalty rate means the highest percent rate payable to the United States, as specified in the lease, in the amount or value of the production saved, removed, or sold.
Lease period means the time from lease issuance until relinquishment, expiration, or termination.
Lowest royalty rate means the lowest percent rate payable to the United States, as specified in the lease, in the amount or value of the production saved, removed, or sold.
OCS lease sale means the Department of the Interior (DOI) proceeding by which leases for certain OCS tracts are offered for sale by competitive bidding and during which bids are received, announced, and recorded.
Pre-Act lease means a lease that:
(1) Is issued as part of an OCS lease sale held before November 28, 1995;
(2) Is located in the Gulf of Mexico in water depths of 200 meters or deeper; and
(3) Lies wholly west of 87 degrees, 30 minutes West longitude. (See part 203 of this title.)
Production period means the period during which the amount of oil and gas produced from a tract (or, if the tract is unitized, the amount of oil and gas as allocated under a unitization formula) will be measured for purposes of determining the amount of royalty payable to the United States
Qualified bidder means a person who has met the appropriate requirements of 30 CFR part 256, subpart G of this title.
Royalty rate means the percentage of the amount or value of the production saved, removed, or sold that is due and payable to the United States Government.
Royalty suspension (RS) lease means a lease that:
(1) Is issued as part of an OCS lease sale held after November 28, 2000;
(2) Is in locations or planning areas specified in a particular Notice of OCS Lease Sale; and
(3) Is offered subject to a royalty suspension specified in a Notice of OCS Lease Sale published in the Federal Register.
Tract means a designation assigned solely for administrative purposes to a block or combination of blocks that are identified by a leasing map or an official protraction diagram prepared by the DOI.
Value of production means the value of all oil and gas production saved, removed, or sold from a tract (or, if the tract is unitized, the value of all oil and gas production saved, removed, or sold and credited to the tract under a unitization formula) during a period of production. The value of production is determined under part 206 of this title.
[66 FR 11518, Feb. 23, 2001, as amended at 72 FR 25202, May 4, 2007]
§ 260.110
What bidding systems may MMS use?
We will apply a single bidding system selected from those listed in this section to each tract included in an OCS lease sale. The following table lists bidding systems, the bid variables, and characteristics.
For the bidding system— | The bid variable is the— | And the characteristics are—
(a) Cash bonus bid with a fixed royalty rate of not less than 12.5 percent | Cash bonus | The highest responsible qualified bidder will pay a royalty rate of not less than 12.5 percent at the beginning of the lease period. We will specify the royalty rate for each tract offered in the Notice of OCS Lease Sale published in the Federal Register.
(b) Royalty rate bid with fixed cash bonus | Royalty rate | We will specify the fixed amount of cash bonus the highest responsible qualified bidder must pay in the Notice of OCS Lease Sale published in the Federal Register.
| (c) Cash bonus bid with a sliding royalty rate of not less than 12.5 percent at the beginning of the lease period | Cash bonus | (1) We will calculate the royalty rate the highest responsible qualified bidder must pay using either: (i) A sliding-scale formula, which relates the royalty rate to the adjusted value or volume of production, or (ii) A schedule that establishes the royalty rate that we will apply to specified ranges of the adjusted value or volume of production. (2) We will determine the adjusted value of production by applying an inflation factor to the actual value of production. (3) If you are the successful high bidder, your lease will include the sliding-scale formula or schedule and will specify the lowest and highest royalty rates that will apply. (4) You will pay a royalty rate of not less than 12.5 percent at the beginning of the lease period. (5) We will include the sliding-scale royalty formula or schedule, inflation factor and procedures for making the inflation adjustment and determining the value or amount of production in the Notice of OCS Lease Sale published in the Federal Register.
(d) Cash bonus bid with fixed share of the net profits of no less than 30 percent | Cash bonus | (1) If we award you a lease as the highest responsible qualified bidder, you will determine the amount of the net profit share payment to the United States for each month by multiplying the net profit share base times the net profit share rate, according to § 220.022. You will calculate the net profit share base according to § 220.021. (2) You will pay a net profit share of not less than 30 percent. (3) We will specify the capital recovery factor, as described in § 220.020, and the net profit share rate, both of which may vary from tract to tract, in the Notice of OCS Lease Sale published in the Federal Register.
(e) Cash bonus with variable royalty rate(s) during one or more periods of production | Cash bonus | (1) We may suspend or defer royalty for a period, volume, or value of production. Notwithstanding suspensions or deferrals, we may impose a minimum royalty. The suspensions or deferrals may vary based on prices or price changes of oil and/or gas. (2) You may pay a royalty rate less than 12.5 percent on production but not less than zero percent. (3) We will specify the applicable royalty rates(s) and suspension or deferral magnitudes, formulas, or relationships in the Notice of OCS Lease Sale published in the Federal Register.
(f) Cash bonus with royalty rate(s) based on formula(s) or schedule(s) during one or more periods of production | Cash bonus | We will base the royalty rate on formula(s) or schedule(s) specified in the Notice of OCS Lease Sale published in the Federal Register.
(g) Cash bonus with a fixed royalty rate of not less than 12.5 percent, at the beginning of the lease period, suspension of royalties for a period, volume, or value of production, or depending upon selected characteristics of extraction, and with suspensions that may vary based on the price of production | Cash bonus | Except for periods of royalty suspension, you will pay a fixed royalty rate of not less than 12.5 percent. If we award to you a lease under this system, you must calculate the royalty due during the designated period using the rate, formula, or schedule specified in the lease. We will specify the royalty rate, formula, or schedule in the Notice of OCS Lease Sale published in the Federal Register.
§ 260.111
What conditions apply to the bidding systems that MMS uses?
(a) For each of the bidding systems in § 260.110, we will include an annual rental fee. Other fees and provisions may apply as well. The Notice of OCS Lease Sale published in the Federal Register will specify the annual rental and any other fees the highest responsible qualified bidder must pay and any other provisions.
(b) If we use any deferment or schedule of payments for the cash bonus bid, we will specify and include it in the Notice of OCS Lease Sale published in the Federal Register.
(c) For the bidding systems listed in this subpart, if the bid variable is a cash bonus bid, the highest bid by a qualified bidder determines the amount of cash bonus to be paid. We will include the minimum bid level(s) in the Notice of OCS Lease Sale published in the Federal Register.
(d) For the bidding systems listed in this subpart, if the bid variable is the royalty rate, the highest bid by a qualified bidder determines the royalty rate to be paid. We will include the minimum royalty rate(s) in the Notice of OCS Lease Sale published in the Federal Register.
(e) We may, by rule, add to or modify the bidding systems listed in § 260.110, according to the procedural requirements of the OCSLA, 43 U.S.C. 1331 et seq., as amended by Public Law 95-372, 92 Stat. 629.

Eligible Leases
§ 260.112
How do royalty suspension volumes apply to eligible leases?
Royalty suspension volumes, as specified in section 304 of the Act, apply to eligible leases that meet the criteria in § 260.113. For purposes of this section and §§ 260.113 through 260.117:
(a) Any volumes of production that are not normally royalty-bearing under the lease or the regulations (e.g., fuel gas) do not count against royalty suspension volumes; and
(b) Production includes volumes allocated to a lease under an approved unit agreement.
§ 260.113
When does an eligible lease qualify for a royalty suspension volume?
(a) Your eligible lease may receive a royalty suspension volume only if it is in a field where no current lease produced oil or gas (other than test production) before November 28, 1995. For eligible leases, the bidding system in § 260.110(g) applies only to leases in fields that meet this condition.
(b) You may receive a royalty suspension volume only if your entire lease is west of 87 degrees, 30 minutes West longitude. A field that lies on both sides of that meridian will receive a royalty suspension volume only for those eligible leases lying entirely west of the meridian.
§ 260.114
How does MMS assign and monitor royalty suspension volumes for eligible leases?
(a) We will assign your lease that has a qualifying well (under part 250, subpart A of this title) to an existing field or designate a new field and will notify you and other affected lessees and operating rights holders in the field of that assignment.
(1) Within 15 days of that notification, you or any of the other affected lessees or operating rights holders may file a written request with the Director of MMS (Director) for reconsideration accompanied by a “Statement of Reasons.”
(2) The Director will respond in writing either affirming or reversing the assignment decision. The Director's decision is the final action of the Department of the Interior and is not subject to appeal to the Interior Board of Land Appeals under part 290 of this title and 43 CFR part 4.
(b) We have specified the water depth for each eligible lease in the final Notice of OCS Lease Sale. Our determination of water depth for each lease is final once we issue the lease. We have specified in the Notice the royalty suspension volume applicable to each water depth. The minimum royalty suspension volumes for fields in million barrels of oil equivalent (MMBOE) are shown in the following table:
Water depth | Minimum royalty suspension volume
(1) 200 to 400 meters | 17.5 MMBOE
(2) 400 to 800 meters | 52.5 MMBOE
(3) 800 meters or more | 87.5 MMBOE
(c) Before commencing production, you must:
(1) Notify the MMS Regional Supervisor for Production and Development of your intention to start production; and
(2) Request confirmation of the size of the royalty suspension volume that applies to your eligible lease.
(d) When production (other than test production) first occurs from any of the eligible leases in a field, we will determine what royalty suspension volume applies to the lease(s) in that field. We base the determination for eligible lease(s) on the royalty suspension volumes specified in paragraph (b) of this section and the water depths of eligible leases specified in § 260.117(a).
(e) Your eligible lease may obtain more than one royalty suspension volume. If a new field is discovered on your eligible lease that already benefits from the royalty suspension volume from another field, production from that new field receives a separate royalty suspension.
[66 FR 11518, Feb. 23, 2001, as amended at 67 FR 57739, Sept. 12, 2002]
§ 260.115
How long will a royalty suspension volume for an eligible lease be effective?
A royalty suspension volume for an eligible lease will continue through the end of the month in which cumulative production from the leases in a field entitled to share the royalty suspension volume reaches that volume or the lease period ends.
§ 260.116
How do I measure natural gas production on my eligible lease?
You must measure natural gas production on your eligible lease subject to the royalty suspension volume as follows: 5.62 thousand cubic feet of natural gas, measured according to part 250, subpart L of this title, equals one barrel of oil equivalent.
§ 260.117
What other provisions apply to royalty suspension volumes for eligible leases?
In addition to the provisions in §§ 260.111 through 260.116, the provisions in this section apply to royalty suspension volumes on eligible leases.
(a) If a new field consists of eligible leases in different water-depth categories, the royalty suspension volume associated with the eligible lease in the deepest water applies.
(b) If your eligible lease is the only eligible lease in a field, you do not owe royalty on the production from your lease up to the applicable royalty suspension volume.
(c) If a field consists of more than one eligible lease:
(1) Payment of royalties on the eligible leases' initial production is suspended until cumulative production equals the field's established royalty suspension volume;
(2) Only production from leases entitled to share in the field's royalty suspension volume counts as part of this cumulative production; and
(3) The royalty suspension volume for each eligible lease is equal to each lease's actual production (or production allocated under an approved unit agreement) until the field's royalty suspension volume is reached.
(d) This paragraph applies if we add an eligible lease to a field that has an established royalty suspension volume that we approved under part 203 of this title. This paragraph also applies to a field that has an established royalty suspension volume as a result of production starting from one or more eligible leases in the field. In situations covered by this paragraph:
(1) The field's royalty suspension volume will not change, even if the added lease is in deeper water;
(2) If we granted a royalty suspension volume under part 203 of this title that is larger than the minimum specified for that water depth, the added eligible lease may share in the larger suspension volume;
(3) The eligible lease may receive a royalty suspension volume only to the extent of its production before the cumulative production equals the field's previously established royalty suspension volume; and
(4) Only production from leases entitled to share in the field's previously established royalty suspension volume counts as part of this cumulative production.
(e) A pre-Act lease may receive a royalty suspension volume under part 203 of this title for a field that already has a royalty suspension volume due to eligible leases. If this happens, then:
(1) The eligible and pre-Act leases share a single royalty suspension volume;
(2) The field's royalty suspension volume is the larger of the volume for the eligible leases or the volume MMS grants in response to the pre-Act leases' application; and
(3) The suspension volume for each eligible lease is its actual production from the lease until cumulative production from all leases in the field entitled to share in the field-based suspension volume equals the suspension volume.
(f) If we reassign a well on an eligible lease to another field, the past production from that well:
(1) Will count toward the royalty suspension volume, if any, specified for the field to which it is reassigned; and
(2) Will not count toward the royalty suspension volume, if any, for the field from which it was reassigned.

Royalty Suspension (RS) Leases
§ 260.120
How does royalty suspension apply to leases issued in a sale held after November 2000?
We may issue leases with suspension of royalties for a period, volume or value of production, as authorized in section 303 of the Act. For purposes of this section and §§ 260.121 through 260.124:
(a) Any volumes of production that are not normally royalty-bearing under the lease or the regulations (e.g., fuel gas) do not count against royalty suspension volumes; and
(b) Production includes volumes allocated to a lease under an approved unit agreement.
§ 260.121
When does a lease issued in a sale held after November 2000 get a royalty suspension?
(a) We will specify any royalty suspension for your RS lease in the Notice of OCS Lease Sale published in the Federal Register for the sale in which you acquire the RS lease and will repeat it in the lease document. In addition:
(1) Your RS lease may produce royalty-free the royalty suspension we specify for your lease, even if the field to which we assign it is producing.
(2) The royalty suspension we specify in the Notice of OCS Lease Sale for your lease does not apply to any other leases in the field to which we assign your RS lease.
(b) You may apply for a supplemental royalty suspension for a project under part 203 of this title, if your lease lies:
(1) In the Gulf of Mexico,
(2) In water 200 meters or deeper, and
(3) Wholly west of 87 degrees, 30 minutes West longitude.
(c) Your RS lease retains the royalty suspension with which we issued it even if we deny your application for more relief.
§ 260.122
How long will a royalty suspension volume be effective for a lease issued in a sale held after November 2000?
(a) The royalty suspension volume for your RS lease will continue through the end of the month in which cumulative production from your lease reaches the applicable royalty suspension volume or the lease period ends.
(b)(1) Notwithstanding any royalty suspension under this subpart, you must pay royalty at the lease stipulated rate on:
(i) Any oil produced for any period stipulated in the lease during which the arithmetic average of the daily closing prices on the New York Mercantile Exchange (NYMEX) for light sweet crude oil exceeds a threshold price stipulated in the lease, or
(ii) Any natural gas produced for any period stipulated in the lease during which the arithmetic average of the daily closing prices on the NYMEX for natural gas exceeds a threshold price stipulated in the lease.
(2) You must pay any royalty due under this paragraph, plus late payment interest under § 218.54 of this title, no later than 90 days after the end of the period for which royalty is owed.
(3) Any production on which you must pay royalty under this paragraph will count toward the production volume determined under §§ 260.120 through 260.124.
(c) If you must pay royalty on any product (either oil or natural gas) for any period under paragraph (b), you must continue to pay royalty on that product during the next succeeding period of the same length until the arithmetic average of the daily closing NYMEX prices for that product for that period can be determined. If the arithmetic average of the daily closing prices for that product for that period is less than the threshold price stipulated in the lease, you are entitled to a credit or refund of royalties paid for that period with interest under applicable law.
(d) MMS will adjust the threshold oil and gas prices referred to in paragraph (b) for any period stipulated in the lease by the percentage, if any, by which the implicit price deflator for the gross domestic product changed during the preceding period.
§ 260.123
How do I measure natural gas production for a lease issued in a sale held after November 2000?
You must measure natural gas production subject to the royalty suspension volume for your lease as follows: 5.62 thousand cubic feet of natural gas, measured according to part 250, subpart L of this title, equals one barrel of oil equivalent.
§ 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 an eligible or pre-Act lease?
(a) We will assign your lease that has a qualifying well (under part 250, subpart A of this title) to an existing field or designate a new field and will notify you and other affected lessees and operating rights holders in the field of that assignment.
(1) Within 15 days of the final notification, you or any of the other affected lessees or operating rights holders may file a written request with the Director for reconsideration, accompanied by a Statement of Reasons.
(2) The Director will respond in writing either affirming or reversing the assignment decision. The Director's decision is the final action of the Department of the Interior and is not subject to appeal to the Interior Board of Land Appeals under part 290 of this title and 43 CFR part 4.
(b) If we establish a royalty suspension volume for a field, either as a result of an approved application for royalty relief submitted for a pre-Act lease under part 203 of this title or as the result of production starting from one or more eligible leases in the field, then:
(1) Royalty-free production from your RS lease shares from and counts as part of any royalty suspension volume under § 260.114(d) for the field to which we assign your lease; and
(2) Your RS lease may continue to produce royalty-free up to the royalty suspension we specified for your lease, even if the field to which we assign your RS lease has produced all of its royalty suspension volume.
(c) Your lease may share in a suspension volume larger than the royalty suspension with which we issued it and to the extent we grant a larger volume in response to an application by a pre-Act lease submitted under part 203 of this title. To share in any larger royalty suspension volume, you must file an application described in §§ 203.71 and 203.83. In no case will royalty-free production for your RS lease be less than the royalty suspension specified for your lease.
[66 FR 11518, Feb. 23, 2001, as amended at 67 FR 57739, Sept. 12, 2002]

Bidding System Selection Criteria
§ 260.130
What criteria does MMS use for selecting bidding systems and bidding system components?
In analyzing the application of one of the bidding systems listed in § 260.110 to tracts selected for any OCS lease sale, we may, at our discretion, consider the following purposes and policies. We recognize that each of the purposes and policies may not be specifically applicable to the selection process for a particular bidding system or tract, or may present a conflict that we will have to resolve in the process of bidding system selection. The order of listing does not denote a ranking.
(a) Providing fair return to the Federal Government;
(b) Increasing competition;
(c) Ensuring competent and safe operations;
(d) Avoiding undue speculation;
(e) Avoiding unnecessary delays in exploration, development, and production;
(f) Discovering and recovering oil and gas;
(g) Developing new oil and gas resources in an efficient and timely manner;
(h) Limiting the administrative burdens on Government and industry; and
(i) Providing an opportunity to experiment with various bidding systems to enable us to identify those most appropriate for the satisfaction of the objectives of the United States in OCS lease sales.
Subpart C [Reserved]

Subpart D—Joint Bidding
§ 260.301
What is the purpose of this subpart?
The purpose of this subpart is to encourage participation in OCS oil and gas lease sales by limiting the requirement for filing “Statements of Production” to certain joint bidders.
§ 260.302
What definitions apply to this subpart?
For the purposes of this subpart, all terms used are defined as in § 256.40 of this title.
§ 260.303
What are the joint bidding requirements?
(a) You must file a Statement of Production with the Director, according to the requirements of §§ 256.38 through 256.44 of this title if:
(1) You submit a joint bid for any OCS oil and gas lease during a 6-month bidding period; and
(2) You were chargeable for the prior production period with an average daily production from all sources in excess of 1.6 million barrels of crude oil, natural gas equivalents, and liquefied petroleum products.
(b) The Statement of Production that you file under paragraph (a) of this section must state that you are chargeable for the prior production period with an average daily production in excess of the quantities listed in paragraph (a) of this section.
(c) If your average daily production in the prior production period met or exceeded the quantities specified in paragraph (a) of this section, you may not submit a joint bid for any OCS oil and gas lease during the applicable 6-month bidding period with any other person similarly chargeable. We will disqualify and reject these bids.
(d) If your average daily production in the prior production period met or exceeded the quantities specified in paragraph (a) of this section, you may not enter into an agreement prior to a lease sale that would result in two or more persons, similarly chargeable, acquiring or holding any interest in the tract for which the bid is submitted. We will disqualify and reject these bids.
Pt. 270

PART 270—NONDISCRIMINATION IN THE OUTER CONTINENTAL SHELF
Sec.
270.1
Purpose.
270.2
Application of this part.
270.3
Definitions.
270.4
Discrimination prohibited.
270.5
Complaint.
270.6
Process.
270.7
Remedies.

Authority:
43 U.S.C. 1863.

Source:
50 FR 21048, May 22, 1985, unless otherwise noted.
§ 270.1
Purpose.
The purpose of this part is to implement the provisions of section 604 of the OCSLA of 1978 which provides that “no person shall, on the grounds of race, creed, color, national origin, or sex, be excluded from receiving or participating in any activity, sale, or employment, conducted pursuant to the provisions of . . . the Outer Continental Shelf Lands Act.”
§ 270.2
Application of this part.
This part applies to any contract or subcontract entered into by a lessee or by a contractor or subcontractor of a lessee after the effective date of these regulations to provide goods, services, facilities, or property in an amount of $10,000 or more in connection with any activity related to the exploration for or development and production of oil, gas, or other minerals or materials in the OCS under the Act.
§ 270.3
Definitions.
As used in this part, the following terms shall have the meanings given below:
Contract means any business agreement or arrangement (in which the parties do not stand in the relationship of employer and employee) between a lessee and any person which creates an obligation to provide goods, services, facilities, or property.
Lessee means the party authorized by a lease, grant of right-of-way, or an approved assignment thereof to explore, develop, produce, or transport oil, gas, or other minerals or materials in the OCS pursuant to the Act and this part.
Person means a person or company, including but not limited to, a corporation, partnership, association, joint stock venture, trust, mutual fund, or any receiver, trustee in bankruptcy, or other official acting in a similar capacity for such company.
Subcontract means any business agreement or arrangement (in which the parties do not stand in the relationship of employer and employee) between a lessee's contractor and any person other than a lessee that is in any way related to the performance of any one or more contracts.
§ 270.4
Discrimination prohibited.
No contract or subcontract to which this part applies shall be denied to or withheld from any person on the grounds of race, creed, color, national origin, or sex.
§ 270.5
Complaint.
(a) Whenever any person believes that he or she has been denied a contract or subcontract to which this part applies on the grounds of race, creed, color, national origin, or sex, such person may complain of such denial or withholding to the Regional Director of the OCS Region in which such action is alleged to have occurred. Any complaint filed under this part must be submitted in writing to the appropriate Regional Director not later than 180 days after the date of the alleged unlawful denial of a contract or subcontract which is the basis of the complaint.
(b) The complaint referred to in paragraph (a) of this section shall be accompanied by such evidence as may be available to a person and which is relevant to the complaint including affidavits and other documents.
(c) Whenever any person files a complaint under this part, the Regional Director with whom such complaint is filed shall give written notice of such filing to all persons cited in the complaint no later than 10 days after receipt of such complaint. Such notice shall include a statement describing the alleged incident of discrimination, including the date and the names of persons involved in it.
§ 270.6
Process.
Whenever a Regional Director determines on the basis of any information, including that which may be obtained under § 270.5 of this title, that a violation of or failure to comply with any provision of this subpart probably occurred, the Regional director shall undertake to afford the complainant and the person(s) alleged to have violated the provisions of this part an opportunity to engage in informal consultations, meetings, or any other form of communications for the purpose of resolving the complaint. In the event such communications or consultations result in a mutually satisfactory resolution of the complaint, the complainant and all persons cited in the complaint shall notify the Regional Director in writing of their agreement to such resolution. If either the complainant or the person(s) alleged to have wrongfully discriminated fail to provide such written notice within a reasonable period of time, the Regional Director must proceed in accordance with the provisions of 30 CFR 250, subpart N.
[50 FR 21048, May 22, 1985; 64 FR 9066, Feb. 24, 1999, as amended at 73 FR 20172, Apr. 15, 2008]
§ 270.7
Remedies.
In addition to the penalties available under 30 CFR part 250, subpart N of this title, the Director may invoke any other remedies available to him or her under the Act or regulations for the lessee's failure to comply with provisions of the Act, regulations, or lease.
[50 FR 21048, May 22, 1985; 64 FR 9066, Feb. 24, 1999]
Pt. 280

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

Subpart A—General Information
Sec.
280.1
What definitions apply to this part?
280.2
What is the purpose of this part?
280.3
What requirements must I follow when I conduct prospecting or research activities?
280.4
What activities are not covered by this part?

Subpart B—How To Apply for a Permit or File a Notice
280.10
What must I do before I may conduct prospecting activities?
280.11
What must I do before I may conduct scientific research?
280.12
What must I include in my application or notification?
280.13
Where must I send my application or notification?

Subpart C—Obligations Under This Part

Prohibitions and Requirements
280.20
What must I not do in conducting Geological and Geophysical (G&G) prospecting or scientific research?
280.21
What must I do in conducting G&G prospecting or scientific research?
280.22
What must I do when seeking approval for modifications?
280.23
How must I cooperate with inspection activities?
280.24
What reports must I file?

Interrupted Activities
280.25
When may MMS require me to stop activities under this part?
280.26
When may I resume activities?
280.27
When may MMS cancel my permit?
280.28
May I relinquish my permit?

Environmental Issues
280.29
Will MMS monitor the environmental effects of my activity?
280.30
What activities will not require environmental analysis?
280.31
Whom will MMS notify about environmental issues?

Penalties and Appeals
280.32
What penalties may I be subject to?
280.33
How can I appeal a penalty?
280.34
How can I appeal an order or decision?

Subpart D—Data Requirements

Geological Data and Information
280.40
When do I notify MMS that geological data and information are available for submission, inspection, and selection?
280.41
What types of geological data and information must I submit to MMS?
280.42
When geological data and information are obtained by a third party, what must we both do?

Geophysical Data and Information
280.50
When do I notify MMS that geophysical data and information are available for submission, inspection, and selection?
280.51
What types of geophysical data and information must I submit to MMS?
280.52
When geophysical data and information are obtained by a third party, what must we both do?

Reimbursement
280.60
Which of my costs will be reimbursed?
280.61
Which of my costs will not be reimbursed?

Protections
280.70
What data and information will be protected from public disclosure?
280.71
What is the timetable for release of data and information?
280.72
What procedure will MMS follow to disclose acquired data and information to a contractor for reproduction, processing, and interpretation?
280.73
Will MMS share data and information with coastal States?

Subpart E—Information Collection
280.80
Paperwork Reduction Act statement—information collection.

Authority:
43 U.S.C. 1331 et seq., 42 U.S.C. 4332 et seq., 31 U.S.C. 9701.

Source:
67 FR 46858, July 17, 2002, unless otherwise noted.

Subpart A—General Information
§ 280.1
What definitions apply to this part?
Definitions in this part have the following meaning:
Act means the OCS Lands Act, as amended (43 U.S.C. 1331 et seq.).
Adjacent State means with respect to any activity proposed, conducted, or approved under this part, any coastal State(s):
(l) That is used, or is scheduled to be used, as a support base for geological and geophysical (G&G) prospecting or scientific research activities; or
(2) In which there is a reasonable probability of significant effect on land or water uses from such activity.
Analyzed geological information means data collected under a permit or a lease that have been analyzed. Some examples of analysis include, but are not limited to, identification of lithologic and fossil content, core analyses, laboratory analyses of physical and chemical properties, well logs or charts, results from formation fluid tests, and descriptions of mineral occurrences or hazardous conditions.
Archaeological interest means capable of providing scientific or humanistic understandings of past human behavior, cultural adaptation, and related topics through the application of scientific or scholarly techniques, such as controlled observation, contextual measurement, controlled collection, analysis, interpretation, and explanation.
Archaeological resource means any material remains of human life or activities that are at least 50 years of age and are of archaeological interest.
Coastal environment means the physical, atmospheric, and biological components, conditions, and factors that interactively determine the productivity, state, condition, and quality of the terrestrial ecosystem from the shoreline inward to the boundaries of the coastal zone.
Coastal zone means the coastal waters (including the lands therein and thereunder) and the adjacent shorelands (including the waters therein and thereunder) that are strongly influenced by each other and in proximity to the shorelands of the several coastal States. The coastal zone includes islands, transition and intertidal areas, salt marshes, wetlands, and beaches. The coastal zone extends seaward to the outer limit of the United States territorial sea and extends inland from the shorelines to the extent necessary to control shorelands, the uses of which have a direct and significant impact on the coastal waters, and the inward boundaries of which may be identified by the several coastal States, under the authority in section 305(b)(1) of the Coastal Zone Management Act of 1972.
Coastal Zone Management Act means the Coastal Zone Management Act of 1972, as amended (16 U.S.C. 1451 et seq.).
Data means facts and statistics, measurements, or samples that have not been analyzed, processed, or interpreted.
Deep stratigraphic test means drilling that involves the penetration into the sea bottom of more than 500 feet (152 meters).
Director means the Director of the Minerals Management Service, U.S. Department of the Interior, or an official authorized to act on the Director's behalf.
Geological data and information means data and information gathered through or derived from geological and geochemical techniques, e.g., coring and test drilling, well logging, bottom sampling, or other physical sampling or chemical testing process.
Geological and geophysical (G&G) prospecting activities means the commercial search for mineral resources other than oil, gas, or sulphur. Activities classified as prospecting include, but are not limited to:
(1) Geological and geophysical marine and airborne surveys where magnetic, gravity, seismic reflection, seismic refraction, or the gathering through coring or other geological samples are used to detect or imply the presence of hard minerals; and
(2) Any drilling, whether on or off a geological structure.
Geological and geophysical (G&G) scientific research activities means any investigations related to hard minerals that are conducted on the OCS for academic or scientific research. These investigations would involve gathering and analyzing geological, geochemical, or geophysical data and information that are made available to the public for inspection and reproduction at the earliest practical time. The term does not include commercial G&G exploration or commercial G&G prospecting activities.
Geological sample means a collected portion of the seabed, the subseabed, or the overlying waters acquired while conducting prospecting or scientific research activities.
Geophysical data and information means any data or information gathered through or derived from geophysical measurement or sensing techniques (e.g., gravity, magnetic, or seismic).
Governor means the Governor of a State or the person or entity lawfully designated by or under State law to exercise the powers granted to a Governor under the Act.
Hard minerals means any minerals found on or below the surface of the seabed except for oil, gas, or sulphur.
Interpreted geological information means the knowledge, often in the form of schematic cross sections, 3-dimensional representations, and maps, developed by determining the geological significance of geological data and analyzed and processed geologic information.
Interpreted geophysical information means knowledge, often in the form of seismic cross sections, 3-dimensional representations, and maps, developed by determining the geological significance of geophysical data and processed geophysical information.
Lease means, depending upon the requirements of the context, either:
(1) An agreement issued under section 8 or maintained under section 6 of the Act that authorizes mineral exploration, development and production; or
(2) The area covered by an agreement specified in paragraph (1) of this definition.
Material remains means physical evidence of human habitation, occupation, use, or activity, including the site, location, or context in which evidence is situated.
Minerals means all minerals authorized by an Act of Congress to be produced from “public lands” as defined in section 103 of the Federal Land Policy and Management Act of 1976 (43 U.S.C. 1702). The term includes oil, gas, sulphur, geopressured-geothermal and associated resources.
Notice means a written statement of intent to conduct G&G scientific research that is:
(1) Related to hard minerals on the OCS; and
(2) Not covered under a permit.
Oil, gas, and sulphur means oil, gas, and sulphur, geopressured-geothermal and associated resources, including gas hydrates.
Outer Continental Shelf (OCS) means all submerged lands:
(1) That lie seaward and outside of the area of lands beneath navigable waters as defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301); and
(2) Whose subsoil and seabed belong to the United States and are subject to its jurisdiction and control.
Permit means the contract or agreement, other than a lease, issued under this part. The permit gives a person the right, under appropriate statutes, regulations, and stipulations, to conduct on the OCS:
(1) Geological prospecting for hard minerals;
(2) Geophysical prospecting for hard minerals;
(3) Geological scientific research; or
(4) Geophysical scientific research.
Permittee means the person authorized by a permit issued under this part to conduct activities on the OCS.
Person means:
(1) A citizen or national of the United States;
(2) An alien lawfully admitted for permanent residence in the United States as defined in section 8 U.S.C. 1101(a)(20);
(3) A private, public, or municipal corporation organized under the laws of the United States or of any State or territory thereof, and association of such citizens, nationals, resident aliens or private, public, or municipal corporations, States, or political subdivisions of States; or
(4) Anyone operating in a manner provided for by treaty or other applicable international agreements. The term does not include Federal agencies.
Processed geological or geophysical information means data collected under a permit and later processed or reprocessed.
(1) Processing involves changing the form of data as to facilitate interpretation. Some examples of processing operations may include, but are not limited to:
(i) Applying corrections for known perturbing causes;
(ii) Rearranging or filtering data; and
(iii) Combining or transforming data elements.
(2) Reprocessing is the additional processing other than ordinary processing used in the general course of evaluation. Reprocessing operations may include varying identified parameters for the detailed study of a specific problem area.
Secretary means the Secretary of the Interior or a subordinate authorized to act on the Secretary's behalf.
Shallow test drilling means drilling into the sea bottom to depths less than those specified in the definition of a deep stratigraphic test.
Significant archaeological resource means those archaeological resources that meet the criteria of significance for eligibility of the National Register of Historic Places as defined in 36 CFR 60.4, or its successor.
Third party means any person other than the permittee or a representative of the United States, including all persons who obtain data or information acquired under a permit from the permittee, or from another third party, by sale, trade, license agreement, or other means.
You means a person who applies for and/or obtains a permit, or files a notice to conduct G&G prospecting or scientific research related to hard minerals on the OCS.
§ 280.2
What is the purpose of this part?
The purpose of this part is to:
(a) Allow you to conduct prospecting activities or scientific research activities on the OCS in Federal waters related to hard minerals on unleased lands or on lands under lease to a third party.
(b) Ensure that you carry out prospecting activities or scientific research activities in a safe and environmentally sound manner so as to prevent harm or damage to, or waste of, any natural resources (including any hard minerals in areas leased or not leased), any life (including fish and other aquatic life), property, or the marine, coastal, or human environment.
(c) Inform you and third parties of your legal and contractual obligations.
(d) Inform you and third parties of:
(1) The U.S. Government's rights to access G&G data and information collected under permit on the OCS;
(2) Reimbursement we will make for data and information that are submitted; and
(3) The proprietary terms of data and information that we retain.
§ 280.3
What requirements must I follow when I conduct prospecting or research activities?
You must conduct G&G prospecting activities or scientific research activities under this part according to:
(a) The Act;
(b) The regulations in this part;
(c) Orders of the Director/Regional Director (RD); and
(d) Other applicable statutes, regulations, and amendments.
§ 280.4
What activities are not covered by this part?
This part does not apply to:
(a) G&G prospecting activities conducted by, or on behalf of, the lessee on a lease on the OCS;
(b) Federal agencies;
(c) Postlease activities for mineral resources other than oil, gas, and sulphur, which are covered by regulations at 30 CFR part 282; and
(d) G&G exploration or G&G scientific research activities related to oil, gas, and sulphur, including gas hydrates, which are covered by regulations at 30 CFR part 251.

Subpart B—How To Apply for a Permit or File a Notice
§ 280.10
What must I do before I may conduct prospecting activities?
You must have an MMS-approved permit to conduct G&G prospecting activities, including deep stratigraphic tests, for hard minerals. If you conduct both G&G prospecting activities, you must have a separate permit for each.
§ 280.11
What must I do before I may conduct scientific research?
You may conduct G&G scientific research activities related to hard minerals on the OCS only after you obtain an MMS-approved permit or file a notice.
(a) Permit. You must obtain a permit if the research activities you want to conduct involve:
(1) Using solid or liquid explosives;
(2) Drilling a deep stratigraphic test; or
(3) Developing data and information for proprietary use or sale.
(b) Notice. If you conduct research activities (including federally-funded research) not covered by paragraph (a) of this section, you must file a notice with the regional director at least 30 days before you begin. If you cannot file a 30-day notice, you must provide oral notification before you begin and follow up in writing. You must also inform MMS in writing when you conclude your work.
§ 280.12
What must I include in my application or notification?
(a) Permits. You must submit to the Regional Director a signed original and three copies of the permit application form (Form MMS-134) at least 30 days before the startup date for activities in the permit area. If unusual circumstances prevent you from meeting this deadline, you must immediately contact the Regional Director to arrange an acceptable deadline. The form includes names of persons, type, location, purpose, and dates of activity, as well as environmental and other information. A nonrefundable service fee of $1,900 must accompany your application.
(b) Disapproval of permit application. If we disapprove your application for a permit, the RD will explain the reasons for the disapproval and what you must do to obtain approval.
(c) Notices. You must sign and date a notice that includes:
(1) The name(s) of the person(s) who will conduct the proposed research;
(2) The name(s) of any other person(s) participating in the proposed research, including the sponsor;
(3) The type of research and a brief description of how you will conduct it;
(4) A map, plat, or chart, that shows the location where you will conduct research;
(5) The proposed projected starting and ending dates for your research activity;
(6) The name, registry number, registered owner, and port of registry of vessels used in the operation;
(7) The earliest practical time you expect to make the data and information resulting from your research activity available to the public;
(8) Your plan of how you will make the data and information you collect available to the public;
(9) A statement that you and others involved will not sell or withhold the data and information resulting from your research; and
(10) At your option, the nonexclusive use agreement for scientific research attachment to form MMS-134. (If you submit this agreement, you do not have to submit the material required in paragraphs (c)(7), (c)(8), and (c)(9) of this section.)
[67 FR 46858, July 17, 2002, as amended at 71 FR 40914, July 19, 2006]
§ 280.13
Where must I send my application or notification?
You must apply for a permit or file a notice at one of the following locations:
For the OCS off the * * * | Apply to * * *
(1) State of Alaska | Regional Supervisor for Resource Evaluation, Minerals Management Service, Alaska OCS Region, 949 East 36th Avenue, Anchorage, AK 99508-4363.
(2) Atlantic Coast, Gulf of Mexico, Puerto Rico, or U.S. territories in the Caribbean Sea | Regional Supervisor for Resource Evaluation, Minerals Management Service, Gulf of Mexico OCS Region, 1201 Elmwood Park Boulevard, New Orleans, LA 70123-2394.
(3) States of California, Oregon, Washington, Hawaii, or U.S. territories in the Pacific Ocean | Regional Supervisor for Resource Evaluation, Minerals Management Service, Pacific OCS Region, 770 Paseo Camarillo, Camarillo, CA 93010-6064.

Subpart C—Obligations Under This Part

Prohibitions and Requirements
§ 280.20
What must I not do in conducting Geological and Geophysical (G&G) prospecting or scientific research?
While conducting G&G prospecting or scientific research activities under a permit or notice, you must not:
(a) Interfere with or endanger operations under any lease, right-of-way, easement, right-of-use, notice, or permit issued or maintained under the Act;
(b) Cause harm or damage to life (including fish and other aquatic life), property, or the marine, coastal, or human environment;
(c) Cause harm or damage to any mineral resources (in areas leased or not leased);
(d) Cause pollution;
(e) Disturb archaeological resources;
(f) Create hazardous or unsafe conditions;
(g) Unreasonably interfere with or cause harm to other uses of the area; or
(h) Claim any oil, gas, sulphur, or other minerals you discover while conducting operations under a permit or notice.
§ 280.21
What must I do in conducting G&G prospecting or scientific research?
While conducting G&G prospecting or scientific research activities under a permit or notice, you must:
(a) Immediately report to the RD if you:
(1) Detect hydrocarbon or any other mineral occurrences;
(2) Detect environmental hazards that imminently threaten life and property; or
(3) Adversely affect the environment, aquatic life, archaeological resources, or other uses of the area where you are prospecting or conducting scientific research activities.
(b) Consult and coordinate your G&G activities with other users of the area for navigation and safety purposes.
(c) If you conduct shallow test drilling or deep stratigraphic test drilling activities, you must use the best available and safest technologies that the RD considers economically feasible.
§ 280.22
What must I do when seeking approval for modifications?
Before you begin modified operations, you must submit a written request describing the modifications and receive the RD's oral or written approval. If circumstances preclude a written request, you must make an oral request and follow up in writing.
§ 280.23
How must I cooperate with inspection activities?
(a) You must allow our representatives to inspect your G&G prospecting or any scientific research activities that are being conducted under a permit. They will determine whether operations are adversely affecting the environment, aquatic life, archaeological resources, or other uses of the area.
(b) MMS will reimburse you for food, quarters, and transportation that you provide for our representatives if you send in your reimbursement request to the region that issued the permit within 90 days of the inspection.
§ 280.24
What reports must I file?
(a) You must submit status reports on a schedule specified in the permit and include a daily log of operations.
(b) You must submit a final report of G&G prospecting or scientific research activities under a permit within 30 days after you complete acquisition activities under the permit. You may combine the final report with the last status report and must include each of the following:
(1) A description of the work performed.
(2) Charts, maps, plats and digital navigation data in a format specified by the RD, showing the areas and blocks in which any G&G prospecting or permitted scientific research activities were conducted. Identify the lines of geophysical traverses and their locations including a reference sufficient to identify the data produced during each activity.
(3) The dates on which you conducted the actual prospecting or scientific research activities.
(4) A summary of any:
(i) Hard mineral, hydrocarbon, or sulphur occurrences encountered;
(ii) Environmental hazards; and
(iii) Adverse effects of the G&G prospecting or scientific research activities on the environment, aquatic life, archaeological resources, or other uses of the area in which the activities were conducted.
(5) Other descriptions of the activities conducted as specified by the RD.

Interrupted Activities
§ 280.25
When may MMS require me to stop activities under this part?
(a) We may temporarily stop prospecting or scientific research activities under a permit when the RD determines that:
(1) Activities pose a threat of serious, irreparable, or immediate harm. This includes damage to life (including fish and other aquatic life), property, and any minerals (in areas leased or not leased), to the marine, coastal, or human environment, or to an archaeological resource;
(2) You failed to comply with any applicable law, regulation, order or provision of the permit. This would include our required submission of reports, well records or logs, and G&G data and information within the time specified; or
(3) Stopping the activities is in the interest of national security or defense.
(b) The RD will advise you either orally or in writing of the procedures to temporarily stop activities. We will confirm an oral notification in writing and deliver all written notifications by courier or certified/registered mail. You must stop all activities under a permit as soon as you receive an oral or written notification.
§ 280.26
When may I resume activities?
The RD will advise you when you may start your permit activities again.
§ 280.27
When may MMS cancel my permit?
The RD may cancel a permit at any time.
(a) If we cancel your permit, the RD will advise you by certified or registered mail 30 days before the cancellation date and will state the reason.
(b) After we cancel your permit, you are still responsible for proper abandonment of any drill site according to the requirements of 30 CFR 251.7(b)(8). You must comply with all other obligations specified in this part or in the permit.
§ 280.28
May I relinquish my permit?
(a) You may relinquish your permit at any time by advising the RD by certified or registered mail 30 days in advance.
(b) After you relinquish your permit, you are still responsible for proper abandonment of any drill sites according to the requirements of 30 CFR 251.7(b)(8). You must also comply with all other obligations specified in this part or in the permit.

Environmental Issues
§ 280.29
Will MMS monitor the environmental effects of my activity?
We will evaluate the potential of proposed prospecting or scientific research activities for adverse impact on the environment to determine the need for mitigation measures.
§ 280.30
What activities will not require environmental analysis?
We anticipate that activities of the type listed below typically will not cause significant environmental impact and will normally be categorically excluded from additional environmental analysis. The types of activities include:
(a) Gravity and magnetometric observations and measurements;
(b) Bottom and subbottom acoustic profiling or imaging without the use of explosives;
(c) Hard minerals sampling of a limited nature such as shallow test drilling;
(d) Water and biotic sampling, if the sampling does not adversely affect shellfish beds, marine mammals, or an endangered species or if permitted by the National Marine Fisheries Service or another Federal agency;
(e) Meteorological observations and measurements, including the setting of instruments;
(f) Hydrographic and oceanographic observations and measurements, including the setting of instruments;
(g) Sampling by box core or grab sampler to determine seabed geological or geotechnical properties;
(h) Television and still photographic observation and measurements;
(i) Shipboard hard mineral assaying and analysis; and
(j) Placement of positioning systems, including bottom transponders and surface and subsurface buoys reported in Notices to Mariners.
§ 280.31
Whom will MMS notify about environmental issues?
(a) In cases where Coastal Zone Management Act consistency review is required, the Director will notify the Governor of each adjacent State with a copy of the application for a permit immediately upon the submission for approval.
(b) In cases where an environmental assessment is to be prepared, the Director will invite the Governor of each adjacent State to review and provide comments regarding the proposed activities. The Director's invitation to provide comments will allow the Governor a specified period of time to comment.
(c) When a permit is issued, the Director will notify affected parties including each affected coastal State, Federal agency, local government, and special interest organization that has expressed an interest.

Penalties and Appeals
§ 280.32
What penalties may I be subject to?
(a) Penalties for noncompliance under a permit. You are subject to the penalty provisions of section 24 of the Act (43 U.S.C. 1350) and the procedures contained in 30 CFR part 250, subpart N for noncompliance with:
(1) Any provision of the Act;
(2) Any provisions of a G&G or drilling permit; or
(3) Any regulation or order issued under the Act.
(b) Penalties under other laws and regulations. The penalties prescribed in this section are in addition to any other penalty imposed by any other law or regulation.
§ 280.33
How can I appeal a penalty?
See 30 CFR § 250.1409 and 30 CFR part 290, subpart A, for instructions on how to appeal any decision assessing a civil penalty under 43 U.S.C. 1350 and 30 CFR part 250, subpart A.
§ 280.34
How can I appeal an order or decision?
See 30 CFR part 290, subpart A, for instructions on how to appeal an order or decision.

Subpart D—Data Requirements

Geological Data and Information
§ 280.40
When do I notify MMS that geological data and information are available for submission, inspection, and selection?
(a) You must notify the RD, in writing, when you complete the initial analysis, processing, or interpretation of any geological data and information. Initial analysis and processing are the stages of analysis or processing where the data and information first become available for in-house interpretation by the permittee or become available commercially to third parties via sale, trade, license agreement, or other means.
(b) The RD may ask if you have further analyzed, processed, or interpreted any geological data and information. When asked, you must respond to us in writing within 30 days.
(c) The RD may ask you or a third party to submit the analyzed, processed, or interpreted geologic data and information for us to inspect or permanently retain. You must submit the data and information within 30 days after such a request.
§ 280.41
What types of geological data and information must I submit to MMS?
Unless the RD specifies otherwise, you must submit geological data and information that include:
(a) An accurate and complete record of all geological (including geochemical) data and information describing each operation of analysis, processing, and interpretation;
(b) Paleontological reports identifying by depth any microscopic fossils collected, including the reference datum to which paleontological sample depths are related and, if the RD requests, washed samples, that you maintain for paleontological determinations;
(c) Copies of well logs or charts in a digital format, if available;
(d) Results and data obtained from formation fluid tests;
(e) Analyses of core or bottom samples and/or a representative cut or split of the core or bottom sample;
(f) Detailed descriptions of any hydrocarbons or other minerals or hazardous conditions encountered during operations, including near losses of well control, abnormal geopressures, and losses of circulation; and
(g) Other geological data and information that the RD may specify.
§ 280.42
When geological data and information are obtained by a third party, what must we both do?
A third party may obtain geological data and information from a permittee, or from another third party, by sale, trade, license agreement, or other means. If this happens:
(a) The third-party recipient of the data and information assumes the obligations under this part, except for the notification provisions of § 280.40(a) and is subject to the penalty provisions of § 280.32(a)(1) and 30 CFR part 250, subpart N; and
(b) A permittee or third party that sells, trades, licenses, or otherwise provides data and information to a third party must advise the recipient, in writing, that accepting these obligations is a condition precedent of the sale, trade, license, or other agreement; and
(c) Except for license agreements, a permittee or third party that sells, trades, or otherwise provides data and information to a third party must advise the RD in writing within 30 days of the sale, trade, or other agreement, including the identity of the recipient of the data and information; or
(d) For license agreements, a permittee or third party that licenses data and information to a third party must, within 30 days of a request by the RD, advise the RD, in writing, of the license agreement, including the identity of the recipient of the data and information.

Geophysical Data and Information
§ 280.50
When do I notify MMS that geophysical data and information are available for submission, inspection, and selection?
(a) You must notify the RD in writing when you complete the initial processing and interpretation of any geophysical data and information. Initial processing is the stage of processing where the data and information become available for in-house interpretation by the permittee, or become available commercially to third parties via sale, trade, license agreement, or other means.
(b) The RD may ask whether you have further processed or interpreted any geophysical data and information. When asked, you must respond to us in writing within 30 days.
(c) The RD may request that the permittee or third party submit geophysical data and information before making a final selection for retention. Our representatives may inspect and select the data and information on your premises, or the RD can request delivery of the data and information to the appropriate regional office for review.
(d) You must submit the geophysical data and information within 30 days of receiving the request, unless the RD extends the delivery time.
(e) At any time before final selection, the RD may review and return any or all geophysical data and information. We will notify you in writing of any data the RD decides to retain.
§ 280.51
What types of geophysical data and information must I submit to MMS?
Unless the RD specifies otherwise, you must include:
(a) An accurate and complete record of each geophysical survey conducted under the permit, including digital navigational data and final location maps;
(b) All seismic data collected under a permit presented in a format and of a quality suitable for processing;
(c) Processed geophysical information derived from seismic data with extraneous signals and interference removed, presented in a quality format suitable for interpretive evaluation, reflecting state-of-the-art processing techniques; and
(d) Other geophysical data, processed geophysical information, and interpreted geophysical information including, but not limited to, shallow and deep subbottom profiles, bathymetry, sidescan sonar, gravity and magnetic surveys, and special studies such as refraction and velocity surveys.
§ 280.52
When geophysical data and information are obtained by a third party, what must we both do?
A third party may obtain geophysical data, processed geophysical information, or interpreted geophysical information from a permittee, or from another third party, by sale, trade, license agreement, or other means. If this happens:
(a) The third-party recipient of the data and information assumes the obligations under this part, except for the notification provisions of § 280.50(a) and is subject to the penalty provisions of § 280.32(a)(1) and 30 CFR 250, subpart N; and
(b) A permittee or third party that sells, trades, licenses, or otherwise provides data and information to a third party must advise the recipient, in writing, that accepting these obligations is a condition precedent of the sale, trade, license, or other agreement; and
(c) Except for license agreements, a permittee or third party that sells, trades, or otherwise provides data and information to a third party must advise the RD, in writing within 30 days of the sale, trade, or other agreements, including the identity of the recipient of the data and information; or
(d) For license agreements, a permittee or third party that licenses data and information to a third party must, within 30 days of a request by the RD, advise the RD, in writing, of the license agreement, including the identity of the recipient of the data and information.

Reimbursement
§ 280.60
Which of my costs will be reimbursed?
(a) We will reimburse you or a third party for reasonable costs of reproducing data and information that the RD requests if:
(1) You deliver G&G data and information to us for the RD to inspect or select and retain (according to §§ 280.40 and 280.50);
(2) We receive your request for reimbursement and the RD determines that the requested reimbursement is proper; and
(3) The cost is at your lowest rate (or a third party's) or at the lowest commercial rate established in the area, whichever is less.
(b) We will reimburse you or the third party for the reasonable costs of processing geophysical information (which does not include cost of data acquisition) if, at the request of the RD, you processed the geophysical data or information in a form or manner other than that used in the normal conduct of business.
§ 280.61
Which of my costs will not be reimbursed?
(a) When you request reimbursement, you must identify reproduction and processing costs separately from acquisition costs.
(b) We will not reimburse you or a third party for data acquisition costs or for the costs of analyzing or processing geological information or interpreting geological or geophysical information.

Protections
§ 280.70
What data and information will be protected from public disclosure?
In making data and information available to the public, the RD will follow the applicable requirements of:
(a) The Freedom of Information Act (5 U.S.C. 552);
(b) The implementing regulations at 43 CFR part 2;
(c) The Act; and
(d) The regulations at 30 CFR parts 250 and 252.
(1) If the RD determines that any data or information is exempt from disclosure under the Freedom of Information Act, we will not disclose the data and information unless either:
(i) You and all third parties agree to the disclosure; or
(ii) A provision of 30 CFR parts 250 and 252 allows us to make the disclosure.
(2) We will keep confidential the identity of third-party recipients of data and information collected under a permit. We will not release the identity unless you and the third parties agree to the disclosure.
(3) When you detect any significant hydrocarbon occurrences or environmental hazards on unleased lands during drilling operations, the RD will immediately issue a public announcement. The announcement must further the national interest without unduly damaging your competitive position.
§ 280.71
What is the timetable for release of data and information?
We will release data and information that you or a third party submits and we retain according to paragraphs (a) and (b) of this section.
(a) If the data and information are not related to a deep stratigraphic test, we will release them to the public according to items (1), (2), and (3) in the following table:
If you or a third party submits and we retain * * * | The Regional Director will disclose them to the public * * *
(1) Geological data and information | 10 years after issuing the permit.
(2) Geophysical data | 50 years after you or a third party submit the data.
(3) Geophysical information | 25 years after you or a third party submit the information
(4) Data and information related to a deep stratigraphic test | 25 years after you complete the test, unless the provisions of paragraph (b) of this section apply.
(b) This paragraph applies if you are covered by paragraph (a)(4) of this section and a lease sale is held or a noncompetitive agreement is negotiated after you complete a test well. We will release the data and information related to the deep stratigraphic test at the earlier of the following times:
(1) Twenty-five years after you complete the test; or
(2) Sixty calendar days after we issue a lease, located partly or totally within 50 geographic miles (92.7 kilometers) of the test.
§ 280.72
What procedure will MMS follow to disclose acquired data and information to a contractor for reproduction, processing, and interpretation?
(a) When practical, the RD will advise the person who submitted data and information under §§ 280.40 or 280.50 of the intent to provide the data or information to an independent contractor or agent for reproduction, processing, and interpretation.
(b) The person notified will have at least five working days to comment on the action.
(c) When the RD advises the person who submitted the data and information, all other owners of the data or information will be considered to have been notified.
(d) The independent contractor or agent must sign a written commitment not to sell, trade, license, or disclose data or information to anyone without the RD's consent.
§ 280.73
Will MMS share data and information with coastal States?
(a) We can disclose proprietary data, information, and samples submitted to us by permittees or third parties that we receive under this part to the Governor of any adjacent State that requests it according to paragraphs (b), (c), and (d) of this section. The permittee or third parties who submitted proprietary data, information, and samples will be notified about the disclosure and will have at least five working days to comment on the action.
(b) We will make a disclosure under this section only after the Governor and the Secretary have entered into an agreement containing all of the following provisions:
(1) The confidentiality of the information will be maintained.
(2) In any action taken for failure to protect the confidentiality of proprietary information, neither the Federal Government nor the State may raise as a defense:
(i) Any claim of sovereign immunity; or
(ii) Any claim that the employee who revealed the proprietary information was acting outside the scope of his/her employment in revealing the information.
(iii) The State agrees to hold the Federal Government harmless for any violation by the State or its employees or contractors of the agreement to protect the confidentiality of proprietary data and information and samples.
(iv) The materials containing the proprietary data, information, and samples will remain the property of the Federal Government.
(c) The data, information, and samples available for reproduction to the State(s) under an agreement must be related to leased lands. Data and information on unleased lands may be viewed but not copied or reproduced.
(d) The State must return to us the materials containing the proprietary data, information, and samples when we ask for them or when the State no longer needs them.
(e) Information received and knowledge gained by a State official under paragraph (d) of this section is subject to confidentiality requirements of:
(1) The Act; and
(2) The regulations at 30 CFR parts 280, 281, and 282.

Subpart E—Information Collection
§ 280.80
Paperwork Reduction Act statement—information collection.
(a) The Office of Management and Budget (OMB) has approved the information collection requirements in this part under 44 U.S.C. 3501 et seq. and assigned OMB control number 1010-0072. The title of this information collection is “30 CFR Part 280, Prospecting for Minerals other than Oil, Gas, and Sulphur on the Outer Continental Shelf.”
(b) We may not conduct or sponsor, and you are not required to respond to, a collection of information unless it displays a currently valid OMB control number.
(c) We use the information collected under this part to:
(1) Evaluate permit applications and monitor scientific research activities for environmental and safety reasons.
(2) Determine that prospecting does not harm resources, result in pollution, create hazardous or unsafe conditions, or interfere with other users in the area.
(3) Approve reimbursement of certain expenses.
(4) Monitor the progress and activities carried out under an OCS prospecting permit.
(5) Inspect and select G&G data and information collected under an OCS prospecting permit.
(d) Respondents are Federal OCS permittees and notice filers. Responses are mandatory or are required to obtain or retain a benefit. We will protect information considered proprietary under applicable law and under regulations at § 280.70 and 30 CFR part 281.
(e) Send comments regarding any aspect of the collection of information under this part, including suggestions for reducing the burden, to the Information Collection Clearance Officer, Minerals Management Service, Mail Stop 4230, 1849 C Street, NW., Washington, DC 20240.
Pt. 281

PART 281—LEASING OF MINERALS OTHER THAN OIL, GAS, AND SULPHUR IN THE OUTER CONTINENTAL SHELF

Subpart A—General
Sec.
281.0
Authority for information collection.
281.1
Purpose and applicability.
281.2
Authority.
281.3
Definitions.
281.4
Qualifications of lessees.
281.5
False statements.
281.6
Appeals.
281.7
Disclosure of information to the public.
281.8
Rights to minerals.
281.9
Jurisdictional controversies.

Subpart B—Leasing Procedures
281.11
Unsolicited request for a lease sale.
281.12
Request for OCS mineral information and interest.
281.13
Joint State/Federal coordination.
281.14
OCS mining area identification.
281.15
Tract size.
281.16
Proposed leasing notice.
281.17
Leasing notice.
281.18
Bidding system.
281.19
Lease term.
281.20
Submission of bids.
281.21
Award of leases.
281.22
Lease form.
281.23
Effective date of leases.

Subpart C—Financial Considerations
281.26
Payments.
281.27
Annual rental.
281.28
Royalty.
281.29
Royalty valuation.
281.30
Minimum royalty.
281.31
Overriding royalties.
281.32
Waiver, suspension, or reduction of rental, minimum royalty, or production royalty.
281.33
Bonds and bonding requirements.

Subpart D—Assignments and Lease Extensions
281.40
Assignment of leases or interests therein.
281.41
Requirements for filing for transfers.
281.42
Effect of assignment on particular lease.
281.43
Effect of suspensions on lease term.

Subpart E—Termination of Leases
281.46
Relinquishment of leases or parts of leases.
281.47
Cancellation of leases.

Authority:
43 U.S.C. 1334.

Source:
54 FR 2049, Jan. 18, 1989, unless otherwise noted.

Subpart A—General
§ 281.0
Authority for information collection.
The information collection requirements contained in part 281 have been approved by the Office of Management and Budget under 44 U.S.C. 3507 and assigned clearance number 1010-0082. The information is being collected to determine if the applicant for a lease on the Outer Continental Shelf (OCS) is qualified to hold such a lease or to determine if a requested action is warranted. The information will be used to make those determinations. An applicant must respond to obtain or retain a benefit.
[54 FR 2049, Jan. 18, 1989, as amended at 73 FR 20172, Apr. 15, 2008]
§ 281.1
Purpose and applicability.
The purpose of these regulations is to establish procedures under which the Secretary of the Interior (Secretary) will exercise the authority granted to administer a leasing program for minerals other than oil, gas, and sulphur in the OCS. The rules in this part apply exclusively to leasing activities for minerals other than oil, gas, and sulphur in the OCS pursuant to the Act.
§ 281.2
Authority.
The Act authorizes the Secretary to grant leases for any mineral other than oil, gas, and sulphur in any area of the OCS to the qualified persons offering the highest cash bonuses on the basis of competitive bidding upon such royalty, rental, and other terms and conditions as the Secretary may prescribe at the time of offering the area for lease (43 U.S.C. 1337(k)). The Secretary is to administer the leasing provisions of the Act and prescribe the rules and regulations necessary to carry out those provisions (43 U.S.C. 1334(a)).
§ 281.3
Definitions.
When used in this part, the following terms shall have the meaning given below:
Act means the OCS Lands Act, as amended (43 U.S.C. 1331 et seq.).
Adjacent State means with respect to any activity proposed, conducted, or approved under this part, any coastal State—
(1) That is, or is proposed to be, receiving for processing, refining, or transshipping OCS mineral resources commercially recovered from the seabed;
(2) That is used, or is scheduled to be used, as a support base for prospecting, exploration, testing, and mining activities; or
(3) In which there is a reasonable probability of significant effect on land or water uses from such activity.
Director means the Director of the Minerals Management Service (MMS) of the U.S. Department of the Interior or an official authorized to act on the Director's behalf.
Governor means the Governor of a State or the person or entity designated by, or pursuant to, State law to exercise the powers granted to such Governor pursuant to the Act.
Lease means any form of authorization which is issued under section 8 of the Act and which authorizes exploration for, and development and production of, minerals, or the area covered by that authorization, whichever is required by the context.
Lessee means the person authorized by a lease, or an approved assignment thereof, to explore for and develop and produce the leased deposits in accordance with the regulations in this chapter. The term includes all persons holding that authority by or through the lessee.
OCS mineral means a mineral deposit or accretion found on or below the surface of the seabed but does not include oil, gas, sulphur; salt or sand and gravel intended for use in association with the development of oil, gas, or sulphur; or source materials essential to production of fissionable materials which are reserved to the United States pursuant to section 12(e) of the Act.
Outer Continental Shelf means all submerged lands lying seaward and outside of the area of lands beneath navigable waters as defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of which the subsoil and seabed appertain to the United States and are subject to its jurisdiction and control.
Overriding royalty means a royalty created out of the lessee's interest which is over and above the royalty reserved to the lessor in the original lease.
Person means a citizen or national of the United States; an alien lawfully admitted for permanent residency in the United States as defined in 8 U.S.C. 1101(a)(20); a private, public, or municipal corporation organized under the laws of the United States or of any State or territory thereof; an association of such citizens, nationals, resident aliens or private, public, or municipal corporations, States, or political subdivisions of States; or anyone operating in a manner provided for by treaty or other applicable international agreements. The term does not include Federal Agencies.
Secretary means the Secretary of the Interior or an official authorized to act on the Secretary's behalf.
§ 281.4
Qualifications of lessees.
(a) In accordance with section 8(k) of the Act, leases shall be awarded only to qualified persons offering the highest cash bonus bid.
(b) Mineral leases issued pursuant to section 8 of the Act may be held only by:
(1) Citizens and nationals of the United States;
(2) Aliens lawfully admitted for permanent residence in the United States as defined in 8 U.S.C. 1101(a)(20);
(3) Private, public, or municipal corporations organized under the laws of the United States or of any State or of the District of Columbia or territory thereof; or
(4) Associations of such citizens, nationals, resident aliens, or private, public, or municipal corporations, States, or political subdivisions of States.
§ 281.5
False statements.
Under the provisions of 18 U.S.C. 1001, it is a crime punishable by up to 5 years imprisonment or a fine of $10,000, or both, for anyone knowingly and willfully to submit or cause to be submitted to any Agency of the United States any false or fraudulent statement(s) to any matters within the Agency's jurisdiction.
§ 281.6
Appeals.
Any party adversely affected by a decision of an MMS official made pursuant to the provisions of this part shall have the right of appeal pursuant to part 290 of this title, except as provided otherwise in § 281.21 of this part.
§ 281.7
Disclosure of information to the public.
The Secretary shall make data and information available to the public in accordance with the requirements and subject to the limitations of the Act, the Freedom of Information Act (5 U.S.C. 552), and the implementing regulations (30 CFR parts 280 and 282 and 43 CFR part 2).
§ 281.8
Rights to minerals.
(a) Unless otherwise specified in the leasing notice, a lease for OCS minerals shall include rights to all minerals within the leased area except the following;
(1) Minerals subject to rights granted by existing leases;
(2) Oil;
(3) Gas;
(4) Sulphur;
(5) Minerals produced in direct association with oil, gas, or sulphur;
(6) Salt deposits which are identified in the leasing notice as being reserved;
(7) Sand and gravel deposits which are identified in the leasing notice as being reserved; and
(8) Source materials essential to production of fissionable materials which are reserved pursuant to section 12(a) of the Act.
(b) When an OCS mineral lease issued under this part limits the minerals to which rights are granted, such lease shall include rights to minerals produced in direct association with the OCS mineral specified in the lease but not the rights to minerals specifically reserved.
(c) The existence of an OCS mineral, oil and gas, or sulphur lease shall not preclude the issuance of a lease(s) for other OCS minerals in the same area. However, no OCS mineral lease shall authorize or permit the lessee thereunder to unreasonably interfere with or endanger operations under an existing OCS mineral, oil and gas, or sulphur lease.
§ 281.9
Jurisdictional controversies.
In the event of a controversy between the United States and a State as to whether certain lands are subject to Federal or State jurisdiction (43 U.S.C. 1336), either the Governor or the Secretary may initiate negotiations in an attempt to settle the jurisdictional controversy. With the concurrence of the Attorney General, the Secretary may enter into an agreement with a State with respect to OCS mineral activities under the Act or under State authority and to payment and impounding of rents, royalties, and other sums and with respect to the offering of lands for lease pending settlement of the controversy.

Subpart B—Leasing Procedures
§ 281.11
Unsolicited request for a lease sale.
(a) Any person may at any time request that OCS minerals be offered for lease. A request that OCS minerals be offered for lease shall be submitted to the Director and shall contain the following information:
(1) The area to be offered for lease.
(2) The OCS minerals of primary interest.
(3) The available OCS mineral resource and environmental information pertaining to the area of interest to be offered for lease which supports the request.
(b) Within 45 days after receipt of a request submitted under paragraph (a) of this section, the Director shall either initiate steps leading to the offer of OCS minerals for lease and notify the applicant of the action taken or inform the applicant of the reasons for not initiating steps leading to the offer of OCS minerals for lease.
(c) Any interested party may at any time submit information to the Director concerning the scheduling of proposed lease sales of OCS minerals in any area of the OCS. Such information may include but not be limited to any of the following:
(1) Benefits of conducting a lease sale in an area.
(2) Costs of conducting a lease sale in an area.
(3) Geohazards which could be encountered in an area.
(4) Geological information about an area and mineral resource potential.
(5) Environmental information about an area.
(6) Information about known archaeological resources in an area.
§ 281.12
Request for OCS mineral information and interest.
(a) When considering whether to offer OCS minerals for lease, the Secretary, upon the Department of the Interior's own initiative or as a result of a submission under § 281.11, may request indications of interest in the leasing of a specific OCS mineral, a group of OCS minerals, or all OCS minerals in the area being considered for lease. Requests for information and interest shall be published in the Federal Register and may be published elsewhere.
(b) States and local governments, industry, other Federal Agencies, and all interested parties (including the public) may respond to a request for information and interest. All information provided to the Secretary will be considered in the decision whether to proceed with additional steps leading to the offering of OCS minerals for lease.
(c) The Secretary may request specific information concerning the offering of a specific OCS mineral, a group of OCS minerals, or all OCS minerals in a broad area for lease or the offering of one or more discrete tracts which represent a minable orebody. The Secretary's request may ask for comments on OCS areas which have been determined to warrant special consideration and analysis. Requests may be for comments concerning geological conditions or archaeological resources on the seabed; multiple uses of the area proposed for leasing, including navigation, recreation and fisheries; and other socioeconomic, biological, and environmental information relating to the area proposed for leasing.
[54 FR 2049, Jan. 18, 1989, as amended at 59 FR 53094, Oct. 21, 1994]
§ 281.13
Joint State/Federal coordination.
(a) The Secretary may invite the adjacent State Governor(s) to join in, or the adjacent State Governor(s) may request that the Secretary join in, the establishment of a State/Federal task force or some other joint planning or coordination arrangement when industry interest exists for OCS mineral leasing or geological information appears to support the leasing of OCS minerals in specific areas. Participation in joint State/Federal task forces or other arrangements will afford the adjacent State Governor(s) opportunity for access to available data and information about the area; knowledge of progress made in the leasing process and of the results of subsequent exploration and development activities; facilitate the resolution of issues of mutual interest; and provide a mechanism for planning, coordination, consultation, and other activities which the Secretary and the Governor(s) may identify as contributing to the leasing process.
(b) State/Federal task forces or other such arrangement are to be constituted pursuant to such terms and conditions (consistent with Federal law and these regulations) as the Secretary and the adjacent State Governor(s) may agree.
(c) State/Federal task forces or other such arrangements will provide a forum which the Secretary and adjacent State Governor(s) may use for planning, consultation, and coordination on concerns associated with the offering of OCS minerals other than oil, gas, or sulphur for lease.
(d) With respect to the activities authorized under these regulations each State/Federal task force may make recommendations to the Secretary and adjacent State Governor(s) concerning:
(1) The identification of areas in which OCS minerals might be offered for lease;
(2) The potential for conflicts between the exploration and development of OCS mineral resources, other users and uses of the area, and means for resolution or mitigation of these conflicts;
(3) The economic feasibility of developing OCS mineral resources in the area proposed for leasing;
(4) Potential environmental problems and measures that might be taken to mitigate these problems;
(5) Development of guidelines and procedures for safe, environmentally responsible exploration and development practices; and
(6) Other issues of concern to the Secretary and adjacent State Governor(s).
(e) State/Federal task forces or other such arrangements might also be used to conduct or oversee research, studies, or reports (e.g., Environmental Impact Statements).
§ 281.14
OCS mining area identification.
The Secretary, after considering the available OCS mineral resources and environmental data and information, the recommendation of any joint State/Federal task force established pursuant to § 281.13 of this part, and the comments received from interested parties, shall select the tracts to be considered for offering for lease. The selected tracts will be considered in the environmental analysis conducted for the proposed lease offering.
§ 281.15
Tract size.
The size of the tracts to be offered for lease shall be as determined by the Secretary and specified in the leasing notice. It is intended that tracts offered for lease be sufficiently large to include potentially minable OCS mineral orebodies. When the presence of any minable orebody is unknown and additional prospecting is needed to discover and delineate OCS minerals, the size of tracts specified in the leasing notice may be relatively large.
§ 281.16
Proposed leasing notice.
(a) Prior to offering OCS minerals in an area for lease, the Director shall assess the available information including recommendations of any joint State/Federal task force established pursuant to § 281.13 of this part to determine lease sale procedures to be prescribed and to develop a proposed leasing notice which sets out the proposed primary term of the OCS mineral leases to be offered; lease stipulations including measures to mitigate potentially adverse impacts on the environment; and such rental, royalty, and other terms and conditions as the Secretary may prescribe in the leasing notice.
(b) The proposed leasing notice shall be sent to the Governor(s) of any adjacent State(s), and a Notice of its availability shall be published in the Federal Register at least 60 days prior to the publication of the leasing notice.
(c) Written comments of the adjacent State Governor(s) submitted within 60 days after publication of the Notice of Availability of the proposed leasing notice shall be considered by the Secretary.
(d) Prior to publication of the leasing notice, the Secretary shall respond in writing to the comments of the adjacent State Governor(s) stating the reasons for accepting or rejecting the Governor's recommendations, or for implementing any alternative mutually acceptable approach identified in consultation with the Governor(s) as a means to provide a reasonable balance between the national interest and the well being of the citizens of the adjacent State.
§ 281.17
Leasing notice.
(a) The Director shall publish the leasing notice in the Federal Register at least 30 days prior to the date that OCS minerals will be offered for lease. The leasing notice shall state whether oral or sealed bids or a combination thereof will be used; the place, date, and time at which sealed bids shall be filed; and the place, date, and time at which sealed bids shall be opened and/or oral bids received. The leasing notice shall contain or reference a description of the tract(s) to be offered for lease; specify the mineral(s) to be offered for lease (if less than all OCS minerals are being offered); specify the period of time the primary term of the lease shall cover; and any stipulation(s), term(s), and condition(s) of the offer to lease (43 U.S.C. 1337(k)).
(b) The leasing notice shall contain a reference to the OCS minerals lease form which shall be issued to successful bidders.
(c) The leasing notice shall specify the terms and conditions governing the payment of the winning bid.
§ 281.18
Bidding system.
(a) The OCS minerals shall be offered by competitive, cash bonus bidding under terms and conditions specified in the leasing notice and in accordance with all applicable laws and regulations.
(b)(1) When the leasing notice specifies the use of sealed bids, such bids received in response to the leasing notice shall be opened at the place, date, and time specified in the leasing notice. The sole purpose of opening bids is to publicly announce and record the bids received, and no bids shall be accepted or rejected at that time.
(2) The Secretary reserves the right to reject any and all sealed bids received for any tract, regardless of the amount offered.
(3) In the event the highest bids are tie bids when using sealed bidding procedures, the tied bidders may be permitted to submit oral bids to determine the highest cash bonus bidder.
(c)(1) When the leasing notice specifies the use of oral bids, oral bids shall be received at the place, time, and date and in accordance with the procedures specified in the leasing notice.
(2) The Secretary reserves the right to reject all oral bids received for any tract, regardless of the amount offered.
(d) When the leasing notice specifies the use of deferred cash bonus bidding, bids shall be received in accordance with paragraph (b) or (c) of this section, as appropriate. The high bid will be determined based upon the net present value of each total bid. The appropriate discount rate will be specified in the leasing notice. High bidders using the deferred bonus option shall pay a minimum of 20 percent of the cash bonus bid prior to lease issuance. At least a total of 60 percent of the cash bonus bid shall be due on or before the 5th anniversary of the lease, and payment of the remainder of the cash bonus bid shall be due on the 10th anniversary of the lease. The lessee shall submit a bond guaranteeing payment of the deferred portion of the bonus, in accordance with § 281.33.
§ 281.19
Lease term.
An OCS mineral lease for OCS minerals other than sand and gravel shall be for a primary term of not less than 20 years as stipulated in the leasing notice. The primary lease term for each OCS mineral shall be determined based on exploration and development requirements for the OCS minerals being offered by the Secretary. An OCS mineral lease for sand and gravel shall be for a primary term of 10 years unless otherwise stipulated in the leasing notice. A lease will continue beyond the specified primary term for so long thereafter as leased OCS minerals are being produced in accordance with an approved mining operation or the lessee is otherwise in compliance with provisions of the lease and the regulations in this chapter under which a lessee can earn continuance of the OCS mineral lease in effect.
§ 281.20
Submission of bids.
(a) If the bidder is an individual, a statement of citizenship shall accompany the bid.
(b) If the bidder is an association (including a partnership), the bid shall be accompanied by a certified statement indicating the State in which it is registered and that the association is authorized to hold mineral leases on the OCS, or appropriate reference to statements or records previously submitted to an MMS OCS office (including material submitted in compliance with prior regulations).
(c) If the bidder is a corporation, the bid shall be accompanied by the following information:
(1) Either a statement certified by the corporate Secretary or Assistant Secretary over the corporate seal showing the State in which it was incorporated and that it is authorized to hold mineral leases on the OCS or appropriate reference to statements or record previously submitted to an MMS OCS office (including material submitted in compliance with prior regulations).
(2) Evidence of authority of persons signing to bind the corporation. Such evidence may be in the form of a certified copy of either the minutes of the board of directors or of the bylaws indicating that the person signing has authority to do so, or a certificate to that effect signed by the Secretary or Assistant Secretary of the corporation over the corporate seal, or appropriate reference to statements or records previously submitted to an MMS OCS office (including material submitted in compliance with prior regulations). Bidders are advised to keep their filings current.
(3) The bid shall be executed in conformance with corporate requirements.
(d) Bidders should be aware of the provisions of 18 U.S.C. 1860, which prohibits unlawful combination or intimidation of bidders.
(e) When sealed bidding is specified in the leasing notice, a separate sealed bid shall be submitted for each bid unit that is bid upon as described in the leasing notice. A bid may not be submitted for less than a bidding unit identified in the leasing notice.
(f) When oral bidding is specified in the leasing notice, information which must accompany a bid pursuant to paragraph (a), (b), or (c) of this section, shall be presented to MMS at the lease sale prior to the offering of an oral bid.
§ 281.21
Award of leases.
(a)(1) The decision of the Director on bids shall be the final action of the Department, subject only to reconsideration by the Secretary, pursuant to a written request in accordance with paragraph (a)(2) of this section. The delegation of review authority to the Office of Hearings and Appeals shall not be applicable to decisions on high bids for leases in the OCS.
(2) Any bidder whose bid is rejected by the Director may file a written request for reconsideration with the Secretary within 15 days of notice of rejection, accompanied by a statement of reasons with a copy to the Director. The Secretary shall respond in writing either affirming or reversing the decision.
(b) Written notice of the Director's action in accepting or rejecting bids shall be transmitted promptly to those bidders whose deposits have been held. If a bid is accepted, such notice shall transmit three copies of the lease form to the successful bidder. As provided in § 281.26 of this part, the bidder shall, not later than the 10th business day after receipt of the lease, execute the lease, pay the first year's rental, and unless payment of a portion of the bid is deferred, pay the balance of the bonus bid. When payment of a portion of the bid is deferred, the successful bidder shall also file a bond to guarantee payment of the deferred portion as required in § 281.33. Deposits shall be refunded on high bids subsequently rejected. When three copies of the lease have been executed by the successful bidder and returned to the Director, the lease shall be executed on behalf of the United States; and one fully executed copy shall be transmitted to the successful bidder.
(c) If the successful bidder fails to execute the lease within the prescribed time or to otherwise comply with the applicable regulations, the successful bidder's deposit shall be forfeited and disposed of in the same manner as other receipts under the Act.
(d) If, before the lease is executed on behalf of the United States, the land which would be subject to the lease is withdrawn or restricted from leasing, the deposit shall be refunded.
(e) If the awarded lease is executed by an agent acting on behalf of the bidder, the bidder shall submit with the executed lease, evidence that the agent is authorized to act on behalf of the bidder.
§ 281.22
Lease form.
The OCS mineral leases shall be issued on the lease form prescribed by the Secretary in the leasing notice.
§ 281.23
Effective date of leases.
Leases issued under the regulations in this part shall be dated and become effective as of the first day of the month following the date leases are signed on behalf of the lessor except that, upon written request, a lease may be dated and become effective as of the first day of the month within which it is signed on behalf of the lessor.

Subpart C—Financial Considerations
§ 281.26
Payments.
(a) For sealed bids, a bonus bid deposit of a specified percentage of the total amount bid is required to be submitted with the bid. The percentage of bonus bid required to be deposited will be specified in the leasing notice. The remittance may be made in cash or by Federal Reserve check, commerical check, bank draft, money order, certified check, or cashier's check made payable to “Department of the Interior—MMS.” Payment of this portion of the bonus bid may not be made by Electronic Funds Transfer.
(b) For oral bids, a bonus bid deposit of a specified percentage of the total amount bid must be submitted to the official designated in the leasing notice following the completion of the oral bidding. The percentage of bonus bid required to be deposited will be specified in the leasing notice. Payment of this portion of the bonus bid shall be made by Electronic Fund Transfer within the timeframe specified in the leasing notice.
(c) The deposit received from high bidders will be placed in a Treasury account pending acceptance or rejection of the bid. Other bids submitted under paragraph (a) of this section will be returned to the bidders. If the high bid is subsequently rejected, an amount equal to that deposited with the high bid will be returned according to applicable regulations.
(d) The balance of the winning bonus bid and all rentals and royalties must be paid in accordance with the terms and conditions of this part, the Leasing Notice, and Subchapter A of this chapter.
(e) For each lease issued pursuant to this subpart, there shall be one person identified who shall be solely responsible for all payments due and payable under the provisions of the lease. The single responsible person shall be designated as the payor for the lease and shall be so identified on the Solid Minerals Production and Royalty Report (P & R) (MMS-4430) in accordance with § 210.201 of this title. The designated person shall be responsible for all bonus, rental, and royalty payments.
(f) Royalty shall be computed at the rate specified in the leasing notice, and paid in value unless the Secretary elects to have the royalty delivered in kind.
(g) For leases which provide for minimum royalty payments, each lessee shall pay the minimum royalty specified in the lease at the end of each lease year beginning with the lease year in which production royalty is paid (whether the full amount specified in the lease or 1/2 the amount specified in the lease pursuant to § 281.28(b) on this part) of OCS minerals produced (sold, transferred, used, or otherwise disposed of) from the leasehold.
(h) Unless stated otherwise in the lease, product valuation will be in accordance with the regulations of this chapter. The value used in the computation of royalty shall be determined by the Director. The value, for royalty purposes, shall be the gross proceeds received by the lessee for produced substances at the point the product is produced and placed in its first marketable condition, consistent with prevailing practices in the industry. In establishing the value, the Director shall consider, in this order: (1) The price received by the lessee; (2) commodity and spot market transactions; (3) any other valuation method proposed by the lessee and approved by the Director; and (4) value or cost netback. For non-arm's length transactions, the first benchmark will only be accepted if it is not less than the second benchmark.
(i) All payors must submit payments and payment forms and maintain auditable records in accordance with 30 CFR Chapter II, Subchapter A—Minerals Revenue Management.
[54 FR 2049, Jan. 18, 1989, as amended at 73 FR 20172, Apr. 15, 2008]
§ 281.27
Annual rental.
(a) The annual lease rental shall be due and payable in accordance with the provisions of this section. No rental shall be due or payable under a lease commencing with the first lease anniversary date following the commencement of royalty payments on leasehold production computed on the basis of the royalty rate specified in the lease except that annual rental shall be due for any year in which production from the leasehold is not subject to royalty pursuant to § 281.28.
(b) Unless otherwise specified in the leasing notice and subsequently issued lease, no annual rental payment shall be due during the first 5 years in the life of a lease.
(c) The leasee shall pay an annual rental in the amount specified in the leasing notice and subsequently issued lease not later than the last day prior to the commencement of the rental year.
(d) A rental adjustment schedule and amount may be specified in a leasing notice and subsequently issued lease when a variance is warranted by geologic, geographic, technical, or economic conditions.
§ 281.28
Royalty.
(a) The royalty due the lessor on OCS minerals produced (i.e., sold, transferred, used, or otherwise disposed of) from a lease shall be set out in a separate schedule attached to and made a part of each lease and shall be as specified in the leasing notice. The royalty due on production shall be based on a percentage of the value or amount of the OCS mineral(s) produced, a sum assessed per unit of product, or other such method as the Secretary may prescribe in the leasing notice. When the royalty specified is a sum assessed per unit of product, the amount of the royalty shall be subject to an annual adjustment based on changes in the appropriate price index, when specified in the leasing notice. When the royalty is specified as a percentage of the value or amount of the OCS minerals produced, the Secretary will notify the lessee when and where royalty is to be delivered in kind.
(b) When prescribed in the leasing notice and subsequently issued lease, royalty due on OCS minerals produced from a leasehold will be reduced for up to any 5 consecutive years, as specified by the lessee prior to the commencement of production, during the 1st through 15th year in the life of the lease. No royalty shall be due in any year of the specified 5-year period that occurs during the 1st through 10th years in the life of the lease, and a royalty of one-half the amount specified in the lease shall be due in any year of the specified 5-year period that occurs in the 11th through 15th year in the life of the lease. The lessee shall pay the amount specified in the lease rental for any royalty free year. The minimum royalty specified in the lease shall apply during any year of reduced royalty.
§ 281.29
Royalty valuation.
The method of valuing the product from a leasehold shall be in accordance with regulations of this chapter and procedures prescribed in the leasing notice and subsequently issued lease.
§ 281.30
Minimum royalty.
Unless otherwise specified in the leasing notice, each lease issued pursuant to the regulations in this part shall require the payment of a specified minimum annual royalty beginning with the year in which OCS minerals are produced (sold, transferred, used, or otherwise disposed of) from the leasehold except that the annual rentals shall apply during any year that royalty free production is in effect pursuant to § 281.28(b). Minimum royalty payments shall be offset by royalty paid on production during the lease year. Minimum royalty payments are due at the beginning of the lease year and payable by the end of the month following the end of the lease year for which they are due.
§ 281.31
Overriding royalties.
(a) Subject to the approval of the Secretary, an overriding royalty interest may be created by an assignment pursuant to section 8(e) of the Act. The Secretary may deny approval of an assignment which creates an overriding royalty on a lease whenever that denial is determined to be in the interest of conservation, necessary to prevent premature abandonment of a producing mine, or to make possible the mining of economically marginal or low-grade ore deposits. In any case, the total of applicable overriding royalties may not exceed 2.5 percent or one-half the base royalty due the Federal Government, whichever is less.
(b) No transfer or agreement may be made which creates an overriding royalty interest unless the owner of that interest files an agreement in writing that such interest is subject to the limitations provided in § 281.30 of this part, paragraph (a) of this section, and § 281.32 of this part.
§ 281.32
Waiver, suspension, or reduction of rental, minimum royalty or production royalty.
(a) The Secretary may waive, suspend, or reduce the rental, minimum royalty, and/or production royalty prescribed in a lease for a specified time period when the Secretary determines that it is in the national interest, it will result in the conservation of natural resources of the OCS, it will promote development, or the mine cannot be successfully operated under existing conditions.
(b) An application for waiver, suspension, or reduction of rental, minimum royalty, or production royalty under paragraph (a) of this section shall be filed in duplicate with the Director. The application shall contain the serial number(s) of the lease(s), the name of the lessee(s) of record, and the operator(s) if applicable. The application shall either:
(1)(i) Show the location and extent of all mining operations and a tabulated statement of the minerals mined and subject to royalty for each of the last 12 months immediately prior to filing the application:
(ii) Contain a detailed statement of expenses and costs of operating the lease, the income from the sale of any lease products, and the amount of all overriding royalties and payments out of production paid to others than the United States; and
(iii) All facts showing whether or not the mine(s) can be successfully operated under the royalty fixed in the lease; or
(2) If no production has occurred from the lease, show that the lease cannot be successfully operated under the rental, royalty, and other conditions specified in the lease.
(c) The applicant for a waiver, suspension, or reduction under this section shall file documentation that the lessee and the royalty holders agree to a reduction of all other royalties from the lease so that the aggregate of all other royalties does not exceed one-half the amount of the reduced royalties that would be paid to the United States.
§ 281.33
Bonds and bonding requirements.
(a) When the leasing notice specifies that payment of a portion of the bonus bid can be deferred, the lessee shall be required to submit a surety or personal bond to guarantee payment of a deferred portion of the bid. Upon the payment of the full amount of the cash bonus bid, the lessee's bond will be released.
(b) All bonds to guarantee payment of the deferred portion of the high cash bonus bid furnished by the lessee must be in a form or on a form approved by the Associate Director for Offshore Minerals Management. A single copy of the required form is to be executed by the principal or, in the case of surety bonds, by both the principal and an acceptable surety.
(1) Only those surety bonds issued by qualified surety companies approved by the Department of the Treasury shall be accepted. (See Department of the Treasury Circular No. 570 and any supplemental or replacement circulars.)
(2) Personal bonds shall be accompanied by a cashier's check, certified check, or negotiable U.S. Treasury bonds of an equal value to the amount specified in the bond. Negotiable Treasury bonds shall be accompanied by a proper conveyance of full authority to the Director to sell such securities in case of default in the performance of the terms and conditions of the lease.
(c) Prior to the commencement of any activity on a lease(s), the lessee shall submit a surety or personal bond as described in § 282.40 of this title. Prior to the approval of a Delineation, Testing, or Mining Plan, the bond amount shall be adjusted, if appropriate, to cover the operations and activities described in the proposed plan.
[54 FR 2049, Jan. 18, 1989, as amended at 62 FR 27960, May 22, 1997]

Subpart D—Assignments and Lease Extensions
§ 281.40
Assignment of leases or interests therein.
(a) Subject to the approval of the Secretary, a lease may be assigned, in whole or in part, pursuant to section 8(e) of the Act to anyone qualified to hold a lease.
(b) Any approved assignment shall be deemed to be effective on the first day of the lease month following the date that it is submitted to the Director for approval unless by written request the parties request that the effective date be the first of the month in which the Director approves the assignment.
(c) The assignor shall be liable for all obligations under the lease occurring prior to the effective date of an assignment.
(d) The assignee shall be liable for all obligations under the lease occurring on or after the effective date of an assignment and shall comply with all terms and conditions of the lease and applicable regulations issued under the Act.
§ 281.41
Requirements for filing for transfers.
(a)(1) All instruments of transfer of a lease or of an interest therein including subleases and assignments of record interest shall be filed in triplicate for approval within 90 days from the date of final execution. They shall include a statement over the transferee's own signature with respect to citizenship and qualifications similar to that required of a lessee and shall contain all of the terms and conditions agreed upon by the parties thereto.
(2) An application for approval of any instrument required to be filed shall not be accepted unless accompanied by a nonrefundable fee of $50. Any document not required to be filed by these regulations but submitted for record purposes shall be accompanied by a nonrefundable fee of $50 per lease affected. Such documents may be rejected at the discretion of the authorized officer.
(b) An attorney in fact signing on behalf of the holder of a lease or sublease, shall furnish evidence of authority to execute the assignment or application for approval and the statement required by § 281.20 of this part.
(c) Where an assignment creates separate leases, a bond shall be furnished for each of the resulting leases in the amount prescribed in § 282.40 of this title. Where an assignment does not create separate leases, the assignee, if the assignment so provides and the surety consents, may become a joint principal on the bond with the assignor.
(d) An heir or devisee of a deceased holder of a lease or any interest therein shall be recognized as the lawful successor to such lease or interest if evidence of status as an heir or devisee is furnished in the form of:
(1) A certified copy of an appropriate order or decree of the court having jurisdiction over the distribution of the estate, or
(2) If no court action is necessary, the statement of two disinterested persons having knowledge of the fact or a certified copy of the will.
(e) The heirs or devisee shall file statements that they are the persons named as successors to the estate with evidence of their qualifications to hold such lease or interest therein.
(f) In the event an heir or devisee is unable to qualify to hold the lease or interest, the heir or devisee shall be recognized as the lawful successor of the deceased and be entitled to hold the lease for a period not to exceed 2 years from the date of death of the predecessor in interest.
(g) Each obligation under any lease and under the regulations in this part shall inure to the heirs, executors, administrators, successors, or assignees of the lease.
§ 281.42
Effect of assignment on particular lease.
(a) When an assignment is made of all the record title to a portion of the acreage in a lease, the assigned and retained portions of the lease area become segregated into separate and distinct leases. In such a case, the assignee becomes a lessee of the Government as to the segregated tract that is the subject of the assignment and is bound by the terms of the lease as though the lease had been obtained from the United States in the assignee's own name, and the assignment, after its approval, shall be the basis of a new record. Royalty, minimum royalty, and annual rental provisions of the lease shall apply separately to each segregated portion.
(b) Each lease of an OCS mineral created by the segregation of a lease under paragraph (a) of this section shall continue in full force and effect for the remainder of the primary term of the original lease and so long thereafter as minerals are produced from the portion of the lease created by segregation in accordance with operations approved by the Director or the lessee is otherwise in compliance with provisions of the lease or regulations for earning the continuation of the lease in effect.
§ 281.43
Effect of suspensions on lease term.
(a) If the Director orders the suspension of either operations or production, or both, with respect to any lease in its primary term, the primary term of the lease shall be extended by a period of time equivalent to the period of the directed suspension.
(b) If the Director orders or approves the suspension of either operations or production, or both, with respect to any lease that is in force beyond its primary term, the term of the lease shall not be deemed to expire so long as the suspension remains in effect.

Subpart E—Termination of Leases
§ 281.46
Relinquishment of leases or parts of leases.
(a) A lease or any part thereof may be surrendered by the record title holder by filing a written relinquishment with the Director. A relinquishment shall take effect on the date it is filed subject to the continued obligation of the lessee and the surety to:
(1) Make all payments due, including any accrued rentals and royalties; and
(2) Abandon all operations, remove all facilities, and clear the land to be relinquished to the satisfaction of the Director.
(b) Upon relinquishment of a lease, the data and information submitted under the lease will no longer be held confidential and will be available to the public.
§ 281.47
Cancellation of leases.
(a) Whenever the owner of a nonproducing lease fails to comply with any of the provisions of the Act, the lease, or the regulations issued under the Act, and the default continues for a period of 30 days after mailing of notice by registered or certified letter to the lease owner at the owner's record post office address, the Secretary may cancel the lease pursuant to section 5(c) of the Act, and the lessee shall not be entitled to compensation. Any such cancellation is subject to judicial review as provided by section 23(b) of the Act.
(b) Whenever the owner of any producing lease fails to comply with any of the provisions of the Act, the lease, or the regulations issued under the Act, the Secretary may cancel the lease only after judicial proceedings pursuant to section 5(d) of the Act, and the lessee shall not be entitled to compensation.
(c) Any lease issued under the Act, whether producing or not, may be canceled by the Secretary upon proof that it was obtained by fraud or misrepresentation and after notice and opportunity to be heard has been afforded to the lessee.
(d) The Secretary may cancel a lease in accordance with the following:
(1) Cancellation may occur at any time if the Secretary determines after a hearing that:
(i) Continued activity pursuant to such lease would probably cause serious harm or damage to life (including fish and other aquatic life), to property, to any mineral (in areas leased or not leased), to the national security or defense, or to the marine, coastal, or human environment;
(ii) The threat of harm or damage will not disappear or decrease to an acceptable extent within a reasonable period of time; and
(iii) The advantages of cancellation outweigh the advantages of continuing such lease in force;
(2) Cancellation shall not occur unless and until operations under such lease shall have been under suspension or temporary prohibition by the Secretary, with due extension of any lease term continuously for a period of 5 years, or for a lesser period upon request of the lessee; and
(3) Cancellation shall entitle the lessee to receive such compensation as is shown to the Secretary as being equal to the lesser of:
(i) The fair value of the canceled rights as of the date of cancellation, taking into account both anticipated revenues from the lease and anticipated costs, including costs of compliance with all applicable regulations and operating orders, liability for cleanup costs or damages, or both, and all other costs reasonably anticipated on the lease, or
(ii) The excess, if any, over the lessee's revenues from the lease (plus interest thereon from the date of receipt to date of reimbursement) of all consideration paid for the lease and all direct expenditures made by the lessee after the date of issuance of such lease and in connection with exploration or development, or both, pursuant to the lease (plus interest on such consideration and such expenditures from date of payment to date of reimbursement), except that in the case of joint leases which are canceled due to the failure of one or more partners to exercise due diligence, the innocent parties shall have the right to seek damages for such loss from the responsible party or parties and the right to acquire the interests of the negligent party or parties and be issued the lease in question.
(iii) The lessee shall not be entitled to compensation where one of the following circumstances exists when a lease is canceled:
(A) A producing lease is forfeited or is canceled pursuant to section (5)(d) of the Act;
(B) A Testing Plan or Mining Plan is disapproved because of the lessee's failure to demonstrate compliance with the requirements of applicable Federal Law; or
(C) The lessee(s) of a nonproducing lease fails to comply with a provision of the Act, the lease, or regulations issued under the Act, and the noncompliance continues for a period of 30 days or more after the mailing of a notice of noncompliance by registered or certified letter to the lessee(s).
Pt. 282

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

Subpart A—General
Sec.
282.0
Authority for information collection.
282.1
Purpose and authority.
282.2
Scope.
282.3
Definitions.
282.4
Opportunities for review and comment.
282.5
Disclosure of data and information to the public.
282.6
Disclosure of data and information to an adjacent State.
282.7
Jurisdictional controversies.

Subpart B—Jurisdiction and Responsibilities of Director
282.10
Jurisdiction and responsibilities of Director.
282.11
Director's authority.
282.12
Director's responsibilities.
282.13
Suspension of production or other operations.
282.14
Noncompliance, remedies, and penalties.
282.15
Cancellation of leases.

Subpart C—Obligations and Responsibilities of Lessees
282.20
Obligations and responsibilities of lessees.
282.21
Plans, general.
282.22
Delineation Plan.
282.23
Testing Plan.
282.24
Mining Plan.
282.25
Plan Modification.
282.26
Contingency Plan.
282.27
Conduct of operations.
282.28
Environmental protection measures.
282.29
Reports and records.
282.30
Right of use and easement.
282.31
Suspension of production or other operations.

Subpart D—Payments
282.40
Bonds.
282.41
Methods of royalty calculation.
282.42
Payments.

Subpart E—Appeals
282.50
Appeals.

Authority:
43 U.S.C 1334.

Source:
54 FR 2067, Jan. 18, 1989, unless otherwise noted.

Subpart A—General
§ 282.0
Authority for information collection.
The information collection requirements in this part have been approved by the Office of Management and Budget under 44 U.S.C. 3507 and assigned clearance number 1010-0081. The information is being collected to inform the Minerals Management Service (MMS) of general mining operations in the Outer Continental Shalf (OCS). The information will be used to ensure that operations are conducted in a safe and environmentally responsible manner in compliance with governing laws and regulations. The requirement to respond is mandatory.
§ 282.1
Purpose and authority.
(a) The Act authorizes the Secretary to prescribe such rules and regulations as may be necessary to carry out the provisions of the Act (43 U.S.C. 1334). The Secretary is authorized to prescribe and amend regulations that the Secretary determines to be necessary and proper in order to provide for the prevention of waste, conservation of the natural resources of the OCS, and the protection of correlative rights therein. In the enforcement of safety, environmental, and conservation laws and regulations, the Secretary is authorized to cooperate with adjacent States and other Departments and Agencies of the Federal Government.
(b) Subject to the supervisory authority of the Secretary, and unless otherwise specified, the regulations in this part shall be administered by the Director of the MMS.
§ 282.2
Scope.
The rules and regulations in this part apply as of their effective date to all operations conducted under a mineral lease for OCS minerals other than oil, gas, or sulphur issued under the provisions of section 8(k) of the Act.
§ 282.3
Definitions.
When used in this part, the following terms shall have the meaning given below:
Act means the OCS Lands Act, as amended (43 U.S.C. 1331 et seq.).
Adjacent State means with respect to any activity proposed, conducted, or approved under this part, any coastal State—
(1) That is, or is proposed to be, receiving for processing, refining, or transshipment OCS mineral resources commercially recovered from the seabed;
(2) That is used, or is scheduled to be used, as a support base for prospecting, exploration, testing, or mining activities; or
(3) In which there is a reasonable probability of significant effect on land or water uses from such activity.
Contingency Plan means a plan for action to be taken in emergency situations.
Data means geological and geophysical (G&G) facts and statistics or samples which have not been analyzed, processed, or interpreted.
Development means those activities which take place following the discovery of minerals in paying quantities including geophysical activities, drilling, construction of offshore facilities, and operation of all onshore support facilities, which are for the purpose of ultimately producing the minerals discovered.
Director means the Director of MMS of the U.S. Department of the Interior or an official authorized to act on the Director's behalf.
Exploration means the process of searching for minerals on a lease including:
(1) Geophysical surveys where magnetic, gravity, seismic, or other systems are used to detect or imply the presence of minerals;
(2) Any drilling including the drilling of a borehole in which the discovery of a mineral other than oil, gas, or sulphur is made and the drilling of any additional boreholes needed to delineate any mineral deposits; and
(3) The taking of sample portions of a mineral deposit to enable the lessee to determine whether to proceed with development and production.
Geological sample means a collected portion of the seabed, the subseabed, or the overylying waters (when obtained for geochemical analysis) acquired while conducting postlease mining activities.
Governor means the Governor of a State or the person or entity designated by, or pursuant to, State law to exercise the power granted to a Governor.
Information means G&G data that have been analyzed, processed, or interpreted.
Lease means one of the following, whichever is required by the context: Any form of authorization which is issued under section 8 or maintained under section 6 of the Acts and which authorizes exploration for, and development and production of, specific minerals; or the area covered by that authorization.
Lessee means the person authorized by a lease, or an approved assignment thereof, to explore for and develop and produce the leased deposits in accordance with the regulations in this chapter. The term includes all parties holding that authority by or through the lessee.
Major Federal action means any action or proposal by the Secretary which is subject to the provisions of section 102(2)(C) of the National Environmental Policy Act (NEPA) (i.e., an action which will have a significant impact on the quality of the human environment requiring preparation of an Environmental Impact Statement (EIS) pursuant to section 102(2)(C) of NEPA).
Marine environment means the physical, atmospheric, and biological components, conditions, and factors which interactively determine the productivity, state, condition, and quality of the marine ecosystem, including the waters of the high seas, the contiguous zone, transitional and intertidal areas, salt marshes, and wetlands within the coastal zone and on the OCS.
Minerals includes oil, gas, sulphur, geopressured-geothermal and associated resources, and all other minerals which are authorized by an Act of Congress to be produced from “public lands” as defined in section 103 of the Federal Land Policy and Management Act of 1976.
OCS mineral means any mineral deposit or accretion found on or below the surface of the seabed but does not include oil, gas, or sulphur; salt or sand and gravel intended for use in association with the development of oil, gas, or sulphur; or source materials essential to production of fissionable materials which are reserved to the United States pursuant to section 12(e) of the Act.
Operator means the individual, partnership, firm, or corporation having control or management of operations on the lease or a portion thereof. The operator may be a lessee, designated agent of the lessee, or holder of rights under an approved operating agreement.
Outer Continental Shelf means all submerged lands lying seaward and outside of the area of lands beneath navigable waters as defined in section 2 of Submerged Lands Act (43 U.S.C. 1301) and of which the subsoil and seabed appertain to the United States and are subject to its jurisdiction and control.
Person means a citizen or national of the United States; an alien lawfully admitted for permanent residency in the United States as defined in 8 U.S.C. 1101(a)(20); a private, public, or municipal corporation organized under the laws of the United States or of any State or territory thereof; an association of such citizens, nationals, resident aliens or private, public, or municipal corporations, States, or political subdivisions of States; or anyone operating in a manner provided for by treaty or other applicable international agreements. The term does not include Federal Agencies.
Secretary means the Secretary of the Interior or an official authorized to act on the Secretary's behalf.
Testing means removing bulk samples for processing tests and feasibility studies and/or the testing of mining equipment to obtain information needed to develop a detailed Mining Plan.
§ 282.4
Opportunities for review and comment.
(a) In carrying out MMS's responsibilities under the Act and regulations in this part, the Director shall provide opportunities for Governors of adjacent States, State/Federal task forces, lessees and operators, other Federal Agencies, and other interested parties to review proposed activities described in a Delineation, Testing, or Mining Plan together with an analysis of potential impacts on the environment and to provide comments and recommendations for the disposition of the proposed plan.
(b)(1) For Delineation Plans, the adjacent State Governor(s) shall be notified by the Director within 15 days following the submission of a request for approval of a Delineation Plan. Notification shall include a copy of the proposed Delineation Plan and the accompanying environmental information. The adjacent State Governor(s) who wishes to comment on a proposed Delineation Plan may do so within 30 days of the receipt of the proposed plan and the accompanying information.
(2) In cases where an Environmental Assessment is to be prepared, the Director's invitation to provide comments may allow the adjacent State Governor(s) more than 30 days following receipt of the proposed plan to provide comments.
(3) The Director shall notify Federal Agencies, as appropriate, with a copy of the proposed Delineation Plan and the accompanying environmental information within 15 days following the submission of the request. Agencies that wish to comment on a proposed Delineation Plan shall do so within 30 days following receipt of the plan and the accompanying information.
(c)(1) For Testing Plans, the adjacent State Governor(s) shall be notified by the Director within 20 days following submission of a request for approval of a proposed Testing Plan. Notification shall include a copy of the proposed Testing Plan and the accompanying environmental information. The adjacent State Governor(s) who wishes to comment on a proposed Testing Plan may do so within 60 days of the receipt of a plan and the accompanying information.
(2) In cases where an EIS is to be prepared, the Director's invitation to provide comments may allow the adjacent State Governor(s) more than 60 days following receipt of the proposed plan to provide comments.
(3) The Director shall notify Federal Agencies, as appropriate, with a copy of the proposed Testing Plan and the accompanying environmental information within 20 days following the submission of the request. Agencies that wish to comment on a proposed Testing Plan shall do so within 60 days following receipt of the plan and the accompanying information.
(d)(1) For Mining Plans, the adjacent State Governor(s) shall be notified by the Director within 20 days following the submission of a request for approval of a proposed Mining Plan. Notification shall include a copy of the proposed Mining Plan and the accompanying environmental information. The adjacent State Governor(s) who wishes to comment on a proposed Mining Plan may do so within 60 days of the receipt of a plan and the accompanying information.
(2) In cases where an EIS is to be prepared, the Director's invitation to provide comments may allow the adjacent State Governor(s) more than 60 days following receipt of the proposed plan to provide comments.
(3) The Director shall notify Federal Agencies, as appropriate, with a copy of the proposed Mining Plan and the accompanying environmental information within 20 days following the submission of the request. Agencies that wish to comment on a proposed Mining Plan shall do so within 60 days following receipt of the plan and the accompanying information.
(e) When an adjacent State Governor(s) has provided comments pursuant to paragraphs (b), (c), and (d) of this section, the Governor(s) shall be given, in writing, a list of recommendations which are adopted and the reasons for rejecting any of the recommendations of the Governor(s) or for implementing any alternative means identified during consultations with the Governor(s).
§ 282.5
Disclosure of data and information to the public.
(a) The Director shall make data, information, and samples available in accordance with the requirements and subject to the limitations of the Act, the Freedom of Information Act (5 U.S.C. 552), and the implementing regulations (43 CFR part 2).
(b) Geophysical data, processed G&G information, interpreted G&G information, and other data and information submitted pursuant to the requirements of this part shall not be available for public inspection without the consent of the lessee so long as the lease remains in effect, unless the Director determines that earlier limited release of such information is necessary for the unitization of operations on two or more leases, to ensure proper Mining Plans for a common orebody, or to promote operational safety. When the Director determines that early limited release of data and information is necessary, the data and information shall be shown only to persons with a direct interest in the affected lease(s), unitization agreement, or joint Mining Plan.
(c) Geophysical data, processed geophysical information and interpreted geophysical information collected on a lease with high resolution systems (including, but not limited to, bathymetry, side-scan sonar, subbottom profiler, and magnetometer) in compliance with stipulations or orders concerning protection of environmental aspects of the lease may be made available to the public 60 days after submittal to the Director, unless the lessee can demonstrate to the satisfaction of the Director that release of the information or data would unduly damage the lessee's competitive position.
§ 282.6
Disclosure of data and information to an adjacent State.
(a) Proprietary data, information, and samples submitted to MMS pursuant to the requirements of this part shall be made available for inspection by representatives of adjacent State(s) upon request by the Governor(s) in accordance with paragraphs (b), (c), and (d) of this section.
(b) Disclosure shall occur only after the Governor has entered into an agreement with the Secretary providing that:
(1) The confidentiality of the information shall be maintained;
(2) In any action commenced against the Federal Government or the State for failure to protect the confidentiality of proprietary information, the Federal Government or the State, as the case may be, may not raise as a defense any claim of sovereign immunity or any claim that the employee who revealed the proprietary information, which is the basis of the suit, was acting outside the scope of the person's employment in revealing the information;
(3) The State agrees to hold the United States harmless for any violation by the State or its employees or contractors of the agreement to protect the confidentiality of proprietary data, information, and samples; and
(c) The data, information, and samples available for inspection by representatives of adjacent State(s) pursuant to an agreement shall be related to leased lands.
§ 282.7
Jurisdictional controversies.
In the event of a controversy between the United States and a State as to whether certain lands are subject to Federal or State jurisdiction, either the Governor of the State or the Secretary may initiate negotiations in an attempt to settle the jurisdictional controversy. With the concurrence of the Attorney General, the Secretary may enter into an agreement with a State with respect to OCS mineral activities and to payment and impounding of rents, royalties, and other sums and with respect to the issuance or nonissuance of new leases pending settlement of the controversy.

Subpart B—Jurisdiction and Responsibilities of Director
§ 282.10
Jurisdiction and responsibilities of Director.
Subject to the authority of the Secretary, the following activities are subject to the regulations in this part and are under the jurisdiction of the Director: Exploration, testing, and mining operations together with the associated environmental protection measures needed to permit those activities to be conducted in an environmentally responsible manner; handling, measurement, and transportation of OCS minerals; and other operations and activities conducted pursuant to a lease issued under part 281 of this chapter, or pursuant to a right of use and easement granted under this part, by or on behalf of a lessee or the holder of a right of use and easement.
§ 282.11
Director's authority.
(a) In the exercise of jurisdiction under § 282.10, the Director is authorized and directed to act upon the requests, applications, and notices submitted under the regulations in this part; to issue either written or oral orders to govern lease operations; and to require compliance with applicable laws, regulations, and lease terms so that all operations conform to sound conservation practices and are conducted in a manner which is consistent with the following:
(1) Make such OCS minerals available to meet the nation's needs in a timely manner;
(2) Balance OCS mineral resource development with protection of the human, marine, and coastal environments;
(3) Ensure the public a fair and equitable return on OCS minerals leased on the OCS; and
(4) Foster and encourage private enterprise.
(b)(1) The Director is to be provided ready access to all OCS mineral resource data and all environmental data acquired by the lessee or holder of a right of use and easement in the course of operations on a lease or right of use and easement and may require a lessee or holder to obtain additional environmental data when deemed necessary to assure adequate protection of the human, marine, and coastal environments.
(2) The Director is to be provided an opportunity to inspect, cut, and remove representative portions of all samples acquired by a lessee in the course of operations on the lease.
(c) In addition to the rights and privileges granted to a lessee under any lease issued or maintained under the Act, on request, the Director may grant a lessee, subject to such conditions as the Director may prescribe, a right of use and easement to construct and maintain platforms, artificial islands, and/or other installations and devices which are permanently or temporarily attached to the seabed and which are needed for the conduct of leasehold exploration, testing, development, production, and processing activities or other leasehold related operations whether on or off the lease.
(d)(1) The Director may approve the consolidation of two or more OCS mineral leases or portions of two or more OCS mineral leases into a single mining unit requested by lessees, or the Director may require such consolidation when the operation of those leases or portions of leases as a single mining unit is in the interest of conservation of the natural resources of the OCS or the prevention of waste. A mining unit may also include all or portions of one or more OCS mineral leases with all or portions of one or more adjacent State leases for minerals in a common orebody. A single unit operator shall be responsible for submission of required Delineation, Testing, and Mining Plans covering OCS mineral operations for an approved mining unit.
(2) Operations such as exploration, testing, and mining activities conducted in accordance with an approved plan on any lease or portion of a lease which is subject to an approved mining unit shall be considered operations on each of the leases that is made subject to the approved mining unit.
(3) Minimum royalty paid pursuant to a Federal lease, which is subject to an approved mining unit, is creditable against the production royalties allocated to that Federal lease during the lease year for which the minimum royalty is paid.
(4) Any OCS minerals produced from State and Federal leases which are subject to an approved mining unit shall be accounted for separately unless a method of allocating production between State and Federal leases has been approved by the Director and the appropriate State official.
§ 282.12
Director's responsibilities.
(a) The Director is responsible for the regulation of activities to assure that all operations conducted under a lease or right of use and easement are conducted in a manner that protects the environment and promotes orderly development of OCS mineral resources. Those activities are to be designed to prevent serious harm or damage to, or waste of, any natural resource (including OCS mineral deposits and oil, gas, and sulphur resources in areas leased or not leased), any life (including fish and other aquatic life), property, or the marine, coastal, or human environment.
(b)(1) In the evaluation of a Delineation Plan, the Director shall consider whether the plan is consistent with:
(i) The provisions of the lease;
(ii) The provisions of the Act;
(iii) The provisions of the regulations prescribed under the Act;
(iv) Other applicable Federal law; and
(v) Requirements for the protection of the environment, health, and safety.
(2) Within 30 days following the completion of an environmental assessment or other NEPA document prepared pursuant to the regulations implementing NEPA or within 30 days following the comment period provided in § 282.4(b) of this part, the Director shall:
(i) Approve any Delineation Plan which is consistent with the criteria in paragraph (b)(1) of this section;
(ii) Require the lessee to modify any Delineation Plan that is inconsistent with the criteria in paragraph (b)(1) of this section; or
(iii) Disapprove a Delineation Plan when it is determined that an activity proposed in the plan would probably cause serious harm or damage to life (including fish and other aquatic life); to property; to natural resources of the OCS including mineral deposits (in areas leased or not leased); or to the marine, coastal, or human environment, and the proposed activity cannot be modified to avoid the conditions.
(3) The Director shall notify the lessee in writing of the reasons for disapproving a Delineation Plan or for requiring modification of a plan and the conditions that must be met for plan approval.
(c)(1) In the evaluation of a Testing Plan, the Director shall consider whether the plan is consistent with:
(i) The provisions of the lease;
(ii) The provisions of the Act;
(iii) The provisions of the regulations prescribed under the Act;
(iv) Other applicable Federal law;
(v) Environmental, safety, and health requirements; and
(vi) The statutory requirement to protect property, natural resources of the OCS, including mineral deposits (in areas leased or not leased), and the national security or defense.
(2) Within 60 days following the release of a final EIS prepared pursuant to NEPA or within 60 days following the comment period provided in § 282.4(c) of this part, the Director shall:
(i) Approve any Testing Plan which is consistent with the criteria in paragraph (c)(1) of this section;
(ii) Require the lessee to modify any Testing Plan which is inconsistent with the criteria in paragraph (c)(1) of this section; or
(iii) Disapprove any Testing Plan when the Director determines the existence of exceptional geological conditions in the lease area, exceptional resource values in the marine or coastal environment, or other exceptional circumstances and that (A) implementation of the activities described in the plan would probably cause serious harm and damage to life (including fish and other aquatic life), to property, to any mineral deposit (in areas leased or not leased), to the national security or defense, or to the marine, coastal, or human environments; (B) that the threat of harm or damage will not disappear or decrease to an acceptable extent within a reasonable period of time; and (C) the advantages of disapproving the Testing Plan outweigh the advantages of development and production of the OCS mineral resources.
(3) The Director shall notify the lessee in writing of the reason(s) for disapproving a Testing Plan or for requiring modification of a Testing Plan and the conditions that must be met for approval of the plan.
(d)(1) In the evaluation of a Mining Plan, the Director shall consider whether the plan is consistent with:
(i) The provisions of the lease;
(ii) The provisions of the Act;
(iii) The provisions of the regulations prescribed under the Act;
(iv) Other applicable Federal law;
(v) Environmental, safety, and health requirements; and
(vi) The statutory requirements to protect property, natural resources of the OCS, including mineral deposits (in areas leased or not leased), and the national security or defense.
(2) Within 60 days following the release of a final EIS prepared pursuant to NEPA or within 60 days following the comment period provided in § 282.4(d) of this part, the Director shall:
(i) Approve any Mining Plan which is consistent with the criteria in paragraph (d)(1) of this section;
(ii) Require the lessee to modify any Mining Plan which is inconsistent with the criteria in paragraph (d)(1) of this section; or
(iii) Disapprove any Mining Plan when the Director determines the existence of exceptional geological conditions in the lease area, exceptional resource values in the marine or coastal environment, or other exceptional circumstances, and that—
(A) Implementation of the activities described in the plan would probably cause serious harm and damage to life (including fish and other aquatic life), to property, to any mineral deposit (in areas leased or not leased), to the national security or defense, or to the marine, coastal, or human environments;
(B) That the threat of harm or damage will not disappear or decrease to an acceptable extent within a reasonable period of time; and
(C) The advantages of disapproving the Mining Plan outweigh the advantages of development and production of the OCS mineral resources.
(3) The Director shall notify the lessee in writing of the reason(s) for disapproving a Mining Plan or for requiring modification of a Mining Plan and the conditions that must be met for approval of the plan.
(e) The Director shall assure that a scheduled onsite compliance inspection of each facility which is subject to regulations in this part is conducted at least once a year. The inspection shall be to determine that the lessee is in compliance with the requirements of the law; provisions of the lease; the approved Delineation, Testing, or Mining Plan; and the regulations in this part. Additional unscheduled onsite inspections shall be conducted without advance notice to the lessee to assure compliance with the provisions of applicable law; the lease; the approved Delineation, Testing, or Mining Plan; and the regulations in this part.
(f)(1) The Director shall, after completion of the technical and environmental evaluations, approve, disapprove, or require modification of the lessee's requests, applications, plans, and notices submitted pursuant to the provisions of this part; issue orders to govern lease operations; and require compliance with applicable provisions of the law, the regulations, the lease, and the approved Delineation, Testing, or Mining Plans. The Director may give oral orders or approvals whenever prior approval is required before the commencement of an operation or activity. Oral orders or approvals given in response to a written request shall be confirmed in writing within 3 working days after issuance of the order or granting of the oral approval.
(2) The Director shall, after completion of the technical and environmental evaluations, approve, disapprove, or require modification, as appropriate, of the design plan, fabrication plan, and installation plan for platforms, artificial islands, and other installations and devices permanently or temporarily attached to the seabed. The approval, disapproval, or requirement to modify such plans may take the form of a condition of granting a right of use and easement under paragraph (a) of this section or as authorized under any lease issued or maintained under the Act.
(g) The Director shall establish practices and procedures to govern the collection of all rents, royalties, and other payments due the Federal Government in accordance with terms of the leasing notice, the lease, and the applicable Royalty Management regulations listed in § 281.26(i) of this chapter.
(h) The Director may prescribe or approve, in writing or orally, departures from the operating requirements of the regulations of this part when such departures are necessary to facilitate the proper development of a lease; to conserve natural resources; or to protect life (including fish and other aquatic life), property, or the marine, coastal, or human environment.
§ 282.13
Suspension of production or other operations.
(a) The Director may direct the suspension or temporary prohibition of production or any other operation or activity on all or any part of a lease when it has been determined that such suspension or temporary prohibition is in the national interest to:
(1) Facilitate proper development of a lease including a reasonable time to develop a mine and construct necessary support facilities, or
(2) Allow for the construction or negotiation for use of transportation facilities.
(b) The Director may also direct or, at the request of the lessee, approve a suspension or temporary prohibition of production or any other operation or activity, if:
(1) The lessee failed to comply with a provision of applicable law, regulation, order, or the lease;
(2) There is a threat of serious, irreparable, or immediate harm or damage to life (including fish and other aquatic life), property, any mineral deposit, or the marine, coastal, or human environment;
(3) The suspension or temporary prohibition is in the interest of national security or defense;
(4) The suspension or temporary prohibition is necessary for the initiation and conduct of an environmental evaluation to define mitigation measures to avoid or minimize adverse environmental impacts.
(5) The suspension or temporary prohibition is necessary to facilitate the installation of equipment necessary for safety of operations and protection of the environment;
(6) The suspension or temporary prohibition is necessary to allow for undue delays encountered by the lessee in obtaining required permits or consents, including administrative or judicial challenges or appeals;
(7) The Director determines that continued operations would result in premature abandonment of a producing mine, resulting in the loss of otherwise recoverable OCS minerals;
(8) The Director determines that the lessee cannot successfully operate a producing mine due to market conditions that are either temporary in nature or require temporary shutdown and reinvestment in order for the lessee to adapt to the conditions; or
(9) The suspension or temporary prohibition is necessary to comply with judicial decrees prohibiting production or any other operation or activity, or the permitting of those activities, effective the date set by the court for that prohibition.
(c) When the Director orders or approves a suspension or a temporary prohibition of operation or activity including production on all of a lease pursuant to paragraph (a) or (b) of this section, the term of the lease shall be extended for a period of time equal to the period of time that the suspension or temporary prohibition is in effect, except that no lease shall be so extended when the suspension or temporary prohibition is the result of the lessee's gross negligence or willful violation of a provision of the lease or governing regulations.
(d) The Director may, at any time within the period prescribed for a suspension or temporary prohibition issued pursuant to paragraph (b)(2) of this section, require the lessee to submit a Delineation, Testing, or Mining Plan for approval in accordance with the requirements for the approval of such plans in this part.
(e)(1) When the Director orders or issues a suspension or a temporary prohibition pursuant to paragraph (b)(2) of this section, the Director may require the lessee to conduct site-specific studies to identify and evaluate the cause(s) of the hazard(s) generating the suspension or temporary prohibition, the potential for damage from the hazard(s), and the measures available for mitigating the hazard(s). The nature, scope, and content of any study shall be subject to approval by the Director. The lessee shall furnish copies and all results of any such study to the Director. The cost of the study shall be borne by the lessee unless the Director arranges for the cost of the study to be borne by a party other than the lessee. The Director shall make results of any such study available to interested parties and to the public as soon as practicable after the completion of the study and submission of the results thereof.
(2) When the Director determines that measures are necessary, on the basis of the results of the studies conducted in accordance with paragraph (e)(1) of this section and other information available to and identified by the Director, the lessee shall be required to take appropriate measures to mitigate, avoid, or minimize the damage or potential damage on which the suspension or temporary prohibition is based. When deemed appropriate by the Director, the lessee shall submit a revised Delineation, Testing, or Mining Plan to incorporate the mitigation measures required by the Director. In choosing between alternative mitigation measures, the Director shall balance the cost of the required measures against the reduction or potential reduction in damage or threat of damage or harm to life (including fish and other aquatic life), to property, to any mineral deposits (in areas leased or not leased), to the national security or defense, or to the marine, coastal, or human environment.
(f)(1) If under the provisions of paragraphs (b) (2), (3), and (4) of this section, the Director, with respect to any lease, directs the suspension of production or other operations on the entire leasehold, no payment of rental or minimum royalty shall be due for or during the period of the directed suspension and the time for the lessee specify royalty free period of a period of reduced royalty pursuant to § 281.28(b) of this subchapter will be extended for the period of directed suspension. If under the provisions of paragraphs (b) (2), (3), and (4) of this section the Director, with respect to a lease on which there has been no production, directs the suspension of operations on the entire leasehold, no payment of rental shall be due during the period of the directed suspension.
(2) If under the provisions of this section, the Director grants the request of a lessee for a suspension of production or other operations, the lessee's obligations to pay rental, minimum royalty, or royalty shall continue to apply during the period of the approved suspension, unless the Director's approval of the lessee's request for suspension authorizes the payment of a lesser amount during the period of approved suspension. If under the provision of this section, the Director grants a lessee's request for a suspension of production or other operations for a lease which includes provisions for a time period which the lessee may specify during which production from the leasehold would be royalty free or subject to a reduced royalty obligation pursuant to § 281.28(b) of this subchapter, the time during which production from a leasehold may be royalty free or subject to a reduced royalty obligation shall not be extended unless the Director's approval of the suspension specifies otherwise.
(3) If the lease anniversary date falls within a period of suspension for which no rental or minimum royalty payments are required under paragraph (a) of this section, the prorated rentals or minimum royalties are due and payable as of the date the suspension period terminates. These amounts shall be computed and notice thereof given the lessee. The lessee shall pay the amount due within 30 days after receipt of such notice. The anniversary date of a lease shall not change by reason of any period of lease suspension or rental or royalty relief resulting therefrom.
§ 282.14
Noncompliance, remedies, and penalties.
(a)(1) If the Director determines that a lessee has failed to comply with applicable provisions of law; the regulations in this part; other applicable regulations; the lease; the approved Delineation, Testing, or Mining Plan; or the Director's orders or instructions, and the Director determines that such noncompliance poses a threat of immediate, serious, or irreparable damage to the environment, the mine or the deposit being mined, or other valuable mineral deposits or other resources, the Director shall order the lessee to take immediate and appropriate remedial action to alleviate the threat. Any oral orders shall be followed up by service of a notice of noncompliance upon the lessee by delivery in person to the lessee or agent, or by certified or registered mail addressed to the lessee at the last known address.
(2) If the Director determines that the lessee has failed to comply with applicable provisions of law; the regulations in this part; other applicable regulations; the lease; the requirements of an approved Delineation, Testing, or Mining Plan; or the Director's orders or instructions, and such noncompliance does not pose a threat of immediate, serious, or irreparable damage to the environment, the mine or the deposit being mined, or other valuable mineral deposits or other resources, the Director shall serve a notice of noncompliance upon the lessee by delivery in person to the lessee or agent or by certified or registered mail addressed to the lessee at the last known address.
(b) A notice of noncompliance shall specify in what respect(s) the lessee has failed to comply with the provisions of applicable law; regulations; the lease; the requirements of an approved Delineation, Testing, or Mining Plan; or the Director's orders or instructions, and shall specify the action(s) which must be taken to correct the noncompliance and the time limits within which such action must be taken.
(c) Failure of a lessee to take the actions specified in the notice of noncompliance within the time limit specified shall be grounds for a suspension of operations and other appropriate actions, including but not limited to the assessment of a civil penalty of up to $10,000 per day for each violation that is not corrected within the time period specified (43 U.S.C. 1350(b)).
(d) Whenever the Director determines that a violation of or failure to comply with any provision of the Act; or any provision of a lease, license, or permit issued pursuant to the Act; or any provision of any regulation promulgated under the Act probably occurred and that such apparent violation continued beyond notice of the violation and the expiration of the reasonable time period allowed for corrective action, the Director shall follow the procedures concerning remedies and penalties in subpart N, Remedies and Penalties, of part 250 of this title to determine and assess an appropriate penalty.
(e) The remedies and penalties prescribed in this section shall be concurrent and cumulative, and the exercise of one shall not preclude the exercise of the other. Further, the remedies and penalties prescribed in this section shall be in addition to any other remedies and penalties afforded by any other law or regulation (43 U.S.C. 1350(e)).
§ 282.15
Cancellation of leases.
(a) Whenever the owner of a nonproducing lease fails to comply with any of the provisions of the Act, the lease, or the regulations issued under the Act, and the default continues for a period of 30 days after mailing of notice by registered or certified letter to the lease owner at the owner's record post office address, the Secretary may cancel the lease pursuant to section 5(c) of the Act, and the lessee shall not be entitled to compensation. Any such cancellation is subject to judicial review as provided by section 23(b) of the Act.
(b) Whenever the owner of any producing lease fails to comply with any of the provisions of the Act, the lease, or the regulations issued under the Act, the Secretary may cancel the lease only after judicial proceedings pursuant to section 5(d) of the Act, and the lessee shall not be entitled to compensation.
(c) Any lease issued under the Act, whether producing or not, may be canceled by the Secretary upon proof that it was obtained by fraud or misrepresentation and after notice and opportunity to be heard has been afforded to the lessee.
(d) The Secretary may cancel a lease in accordance with the following:
(1) Cancellation may occur at any time if the Secretary determines after a hearing that—
(i) Continued activity pursuant to such lease would probably cause serious harm or damage to life (including fish and other aquatic life), to property, to any mineral (in areas leased or not leased), to the national security or defense, or to the marine, coastal, or human environment;
(ii) The threat of harm or damage will not disappear or decrease to an acceptable extent within a reasonable period of time; and
(iii) The advantages of cancellation outweigh the advantages of continuing such lease in force.
(2) Cancellation shall not occur unless and until operations under such lease shall have been under suspension or temporary prohibition by the Secretary, with due extension of any lease term continuously for a period of 5 years or for a lesser period upon request of the lessee;
(3) Cancellation shall entitle the lessee to receive such compensation as is shown to the Secretary as being equal to the lesser of—
(i) The fair value of the canceled rights as of the date of cancellation, taking account of both anticipated revenues from the lease and anticipated costs, including costs of compliance with all applicable regulations and operating orders, liability for cleanup costs or damages, or both, and all other costs reasonably anticipated on the lease, or
(ii) The excess, if any, over the lessee's revenue from the lease (plus interest thereon from the date of receipt to date of reimbursement) of all consideration paid for the lease and all direct expenditures made by the lessee after the date of issuance of such lease and in connection with exploration or development, or both, pursuant to the lease (plus interest on such consideration and such expenditures from date of payment to date of reimbursement), except that in the case of joint leases which are canceled due to the failure of one or more partners to exercise due diligence, the innocent parties shall have the right to seek damages for such loss from the responsible party or parties and the right to acquire the interests of the negligent party or parties and be issued the lease in question.
(iii) The lessee shall not be entitled to compensation where one of the following circumstances exists when a lease is canceled:
(A) A producing lease is forfeited or is canceled pursuant to section (5)(d) of the Act;
(B) A Testing Plan or Mining Plan is disapproved because the lessee's failure to demonstrate compliance with the requirements of applicable Federal law; or
(C) The lessee of a nonproducing lease fails to comply with a provision of the Act, the lease, or regulations issued under the Act, and the noncompliance continues for a period of 30 days or more after the mailing of a notice of noncompliance by registered or certified letter to the lessee.

Subpart C—Obligations and Responsibilities of Lessees
§ 282.20
Obligations and responsibilities of lessees.
(a) The lessee shall comply with the provisions of applicable laws; regulations; the lease; the requirements of the approved Delineation, Testing, or Mining Plans; and other written or oral orders or instructions issued by the Director when performing exploration, testing, development, and production activities pursuant to a lease issued under part 281 of this title. The lessee shall take all necessary precautions to prevent waste and damage to oil, gas, sulphur, and other OCS mineral-bearing formations and shall conduct operations in such manner that does not cause or threaten to cause harm or damage to life (including fish and other aquatic life); to property; to the national security or defense; or to the marine, coastal, or human environment (including onshore air quality). The lessee shall make all mineral resource data and information and all environmental data and information acquired by the lessee in the course of exploration, testing, development, and production operations on the lease available to the Director for examination and copying at the lease site or an onshore location convenient to the Director.
(b) In all cases where there is more than one lease owner of record, one person shall be designated payor for the lease. The payor shall be responsible for making all rental, minimum royalty, and royalty payments.
(c) In all cases where lease operations are not conducted by the sole lessee, a “designation of operator” shall be submitted to and accepted by the Director prior to the commencement of leasehold operations. This designation when accepted will be recognized as authority for the designee to act on behalf of the lessees and to fulfill the lessees' obligations under the Act, the lease, and the regulations of this part. All changes of address and any termination of a designation of operator shall be reported immediately, in writing, to the Director. In the case of a termination of a designation of operator or in the event of a controversy between the lessee and the designated operator, both the lessee and the designated operator will be responsible for the protection of the interests of the lessor.
(d) When required by the Director or at the option of the lessee, the lessee shall submit to the Director the designation of a local representative empowered to receive notices, provide access to OCS mineral and environmental data and information, and comply with orders issued pursuant to the regulations of this part. If there is a change in the designated representative, the Director shall be notified immediately.
(e) Before beginning operations, the lessee shall inform the Director in writing of any designation of a local representative under paragraph (d) of this section and the address of the mine office responsible for the exploration, testing, development, or production activities; the lessee's temporary and permanent addresses; or the name and address of the designated operator who will be responsible for the operations, and who will act as the local representative of the lessee. The Director shall also be informed of each change thereafter in the address of the mine office or in the name or address of the local representative.
(f) The holder of a right of use and easement shall exercise its rights under the right of use and easement in accordance with the regulations of this part.
(g) A lessee shall submit reports and maintain records in accordance with § 282.29 of this part.
(h) When an oral approval is given by MMS in response to an oral request under these regulations, the oral request shall be confirmed in writing by the lessee or holder of a right of use and easement within 72 hours.
(i) The lessee is responsible for obtaining all permits and approvals from MMS or other Agencies needed to carry out exploration, testing, development, and production activities under a lease issued under part 281 of this title.
§ 282.21
Plans, general.
(a) No exploration, testing, development, or production activities, except preliminary activities, shall be commenced or conducted on any lease except in accordance with a plan submitted by the lessee and approved by the Director. Plans will not be approved before completion of comprehensive technical and environmental evaluations to assure that the activities described will be carried out in a safe and environmentally responsible manner. Prior to the approval of a plan, the Director will assure that the lessee is prepared to take adequate measures to prevent waste; conserve natural resources of the OCS; and protect the environment, human life, and correlative rights. The lessee shall demonstrate to the satisfaction of the Director that the lease is in good standing, the lessee is authorized and capable of conducting the activities described in the plan, and that an acceptable bond has been provided.
(b) Plans shall be submitted to the Director for approval. The lessee shall submit the number of copies prescribed by the Director. Such plans shall describe in detail the activities that are to be conducted and shall demonstrate that the proposed exploration, testing, development, and production activities will be conducted in an operationally safe and environmentally responsible manner that is consistent with the provisions of the lease, applicable laws, and regulations. The Governor of an affected State and other Federal Agencies shall be provided an opportunity to review and provide comments on proposed Delineation, Testing, and Mining Plans and any proposal for a significant modification to an approved plan. Following review, including the technical and environmental evaluations, the Director shall either approve, disapprove, or require the lessee to modify its proposed plan.
(c) Lessees are not required to submit a Delineation or Testing Plan prior to submittal of a proposed Testing or Mining Plan if the lessee has sufficient data and information on which to base a Testing or Mining Plan without carrying out postlease exploration and/or testing activities. A Mining Plan may include proposed exploration or testing activities where those activities are needed to obtain additional data and information on which to base plans for future mining activities. A Testing Plan may include exploration activities when those activities are needed to obtain additional data or information on which to base plans for future testing or mining activities.
(d) Preliminary activities are bathymetric, geological, geophysical, mapping, and other surveys necessary to develop a comprehensive Delineation, Testing, or Mining Plan. Such activities are those which have no significant adverse impact on the natural resources of the OCS. The lessee shall give notice to the Director at least 30 days prior to initiating the proposed preliminary activities on the lease. The notice shall describe in detail those activities that are to be conducted and the time schedule for conducting those activities.
(e) Leasehold activities shall be carried out with due regard to conservation of resources, paying particular attention to the wise management of OCS mineral resources, minimizing waste of the leased resource(s) in mining and processing, and preventing damage to unmined parts of the mineral deposit and other resources of the OCS.
§ 282.22
Delineation Plan.
All exploration activities shall be conducted in accordance with a Delineation Plan submitted by the lessee and approved by the Director. The Delineation Plan shall describe the proposed activities necessary to locate leased OCS minerals, characterize the quantity and quality of the minerals, and generate other information needed for the development of a comprehensive Testing or Mining Plan. A Delineation Plan at a minimum shall include the following:
(a) The OCS mineral(s) or primary interest.
(b) A brief narrative description of the activities to be conducted and how the activities will lead to the discovery and evaluation of a commercially minable deposit on the lease.
(c) The name, registration, and type of equipment to be used, including vessel types as well as their navigation and mobile communication systems, and transportation corridors to be used between the lease and shore.
(d) Information showing that the equipment to be used (including the vessel) is capable of performing the intended operation in the environment which will be encountered.
(e) Maps showing the proposed locations of test drill holes, the anticipated depth of penetration of test drill holes, the locations where surficial sample were taken, and the location of proposed geophysical survey lines for each surveying method being employed.
(f) A description of measures to be taken to avoid, minimize, or otherwise mitigate air, land, and water pollution and damage to aquatic and wildlife species and their habitats; any unique or special features in the lease area; aquifers; other natural resources of the OCS; and hazards to public health, safety, and navigation.
(g) A schedule indicating the starting and completion dates for each proposed exploration activity.
(h) A list of any known archaeological resources on the lease and measures to assure that the proposed exploration activities do not damage those resources.
(i) A description of any potential conflicts with other uses and users of the area.
(j) A description of measures to be taken to monitor the effects of the proposed exploration activities on the environment in accordance with § 282.28(c) of this part.
(k) A detailed description of practices and procedures to effect the abandonment of exploration activities, e.g., plugging of test drill holes. The proposed procedures shall indicate the steps to be taken to assure that test drill holes and other testing procedures which penetrate the seafloor to a significant depth are properly sealed and that the seafloor is left free of obstructions or structures that may present a hazard to other uses or users of the OCS such as navigation or commercial fishing.
(l) A detailed description of the cycle of all materials, the method for discharge and disposal of waste and refuse, and the chemical and physical characteristics of waste and refuse.
(m) A description of the potential environmental impacts of the proposed exploration activities including the following:
(1) The location of associated port, transport, processing, and waste disposal facilities and affected environment (e.g., maps, land use, and layout);
(2) A description of the nature and degree of environmental impacts and the domestic socioeconomic effects of construction and operation of the associated facilities, including waste characteristics and toxicity;
(3) Any proposed mitigation measures to avoid or minimize adverse impacts on the environment;
(4) A certificate of consistency with the federally approved State coastal zone management program, where applicable; and
(5) Alternative sites and technologies considered by the lessee and the reasons why they were not chosen.
(n) Any other information needed for technical evaluation of the planned activity, such as sample analyses to be conducted at sea, and the evaluation of potential environmental impacts.
§ 282.23
Testing Plan.
All testing activities shall be conducted in accordance with a Testing Plan submitted by the lessee and approved by the Director. Where a lessee needs more information to develop a detailed Mining Plan than is obtainable under an approved Delineation Plan, to prepare feasibility studies, to carry out a pilot program to evaluate processing techniques or technology or mining equipment, or to determine environmental effects by a pilot test mining operation, the lessee shall submit a comprehensive Testing Plan for the Director's approval. Any OCS minerals acquired during activities conducted under an approved Testing Plan will be subject to the payment of royalty pursuant to the governing lease terms. A Testing Plan at a minimum shall include the following:
(a) The nature and purpose of the proposed testing program.
(b) A comprehensive description of the activities to be performed including descriptions of the proposed methods for analysis of samples taken.
(c) A narrative description and maps showing water depths and the locations of the proposed pilot mining or other testing activities.
(d) A comprehensive description of the method and manner in which testing activities will be conducted and the results the lessee expects to obtain as a result of those activities.
(e) The name, registration, and type of equipment to be used, including vessel types together with their navigation and mobile communication systems, and transportation corridors to be used between the lease and shore.
(f) Information showing that the equipment to be used (including the vessel) is capable of performing the intended operation in the environment which will be encountered.
(g) A schedule specifying the starting and completion dates for each of the testing activities.
(h) A list of known archaeological resources on the lease and measures to be used to assure that the proposed testing activities do not damage those resources.
(i) A description of any potential conflicts with other uses and users of the area.
(j) A description of measures to be taken to avoid, minimize, or otherwise mitigate air, land, and water pollution and damage to aquatic and wildlife species and their habitat; any unique or special features in the lease area, other natural resources of the OCS; and hazards to public health, safety, and navigation.
(k) A description of the measures to be taken to monitor the impacts of the proposed testing activities in accordance with § 282.28(c) of this part.
(l) A detailed description of the cycle of all materials including samples and wastes, the method for discharge and disposal of waste and refuse, and the chemical and physical characteristics of such waste and refuse.
(m) A detailed description of practices and procedures to effect the abandonment of testing activities, e.g., abandonment of a pilot mining facility. The proposed procedures shall indicate the steps to be taken to assure that mined areas do not pose a threat to the environment and that the seafloor is left free of obstructions and structures that may present a hazard to other uses or users of the OCS such as navigation or commercial fishing.
(n) A description of potential environmental impacts of testing activities including the following:
(1) The location of associated port, transport, processing, and waste disposal facilities and affected environment (e.g., maps, land use, and layout);
(2) A description of the nature and degree of potential environmental impacts of the proposed testing activities and the domestic socioeconomic effects of construction and operation of the proposed testing facilities, including waste characteristics and toxicity;
(3) Any proposed mitigation measures to avoid or minimize adverse impacts on the environment;
(4) A certificate of consistency with the federally approved State coastal zone management program, where applicable; and
(5) Alternate sites and technologies considered by the lessee and the reasons why they were not selected.
(o) Any other information needed for technical evaluation of the planned activities and for evaluation of the impact of those activities on the human, marine, and coastal environments.
§ 282.24
Mining Plan.
All OCS mineral development and production activities shall be conducted in accordance with a Mining Plan submitted by the lessee and approved by the Director. A Mining Plan shall include comprehensive detailed descriptions, illustrations, and explanations of the proposed OCS mineral development, production, and processing activities and accurately present the lessee's proposed plan of operation. A Mining Plan at a minimum shall include the following:
(a) A narrative description of the mining activities including:
(1) The OCS mineral(s) or material(s) to be recovered;
(2) Estimates of the number of tons and grade(s) of ore to be recovered;
(3) Anticipated annual production;
(4) Volume of ocean bottom expected to be disturbed (area and depth of disruption) each year; and
(5) All activities of the mining cycle from extraction through processing and waste disposal.
(b) Maps of the lease showing water depths, the outline of the mineral deposit(s) to be mined with cross sections showing thickness, and the area(s) anticipated to be mined each year.
(c) The name, registration, and type of equipment to be used, including vessel types as well as their navigation and mobile communication systems, and transportation corridors to be used between the lease and shore.
(d) Information showing that the equipment to be used (including the vessel) is capable of performing the intended operation in the environment which will be encountered.
(e) A description of equipment to be used in mining, processing, and transporting of the ore.
(f) A schedule indicating the anticipated starting and completion dates for each activity described in the plan.
(g) For onshore processing, a description of how OCS minerals are to be processed and how the produced OCS minerals will be weighed, assayed, and royalty determinations made.
(h) For at-sea processing, additional information including type and size of installation or structures and the method of tailings disposal.
(i) A list of known archaeological resources on the lease and the measures to be taken to assure that the proposed mining activities do not damage those resources.
(j) Description of any potential conflicts with other uses and users of the area.
(k) A detailed description of the nature and occurrence of the OCS mineral deposit(s) in the leased area with adequate maps and sections.
(l) A detailed description of development and mining methods to be used, the proposed sequence of mining or development, the expected production rate, the method and location of the proposed processing operation, and the method of measuring production.
(m) A detailed description of the method of transporting the produced OCS minerals from the lease to shore and adequate maps showing the locations of pipelines, conveyors, and other transportation facilities and corridors.
(n) A detailed description of the cycle of all materials including samples and wastes, the method of discharge and disposal of waste and refuse, and the chemical and physical characteristics of the waste and refuse.
(o) A description of measures to be taken to avoid, minimize, or otherwise mitigate air, land, and water pollution and damage to aquatic and wildlife species and their habitats; any unique or special features in the lease area, aquifers, or other natural resources of the OCS; and hazards to public health, safety, and navigation.
(p) A detailed description of measures to be taken to monitor the impacts of the proposed mining and processing activities on the environment in accordance with § 282.28(c) of this part.
(q) A detailed description of practices and procedures to effect the abandonment of mining and processing activities. The proposed procedures shall indicate the steps to be taken to assure that mined areas on tailing deposits do not pose a threat to the environment and that the seafloor is left free of obstructions and structures that present a hazard to other users or uses of the OCS such as navigation or commercial fishing.
(r) A description of potential environmental impacts of mining activities including the following:
(1) The location of associated port, transport, processing, and waste disposal facilities and the affected environment (e.g., maps, land use, and layout);
(2) A description of the nature and degree of potential environmental impacts of the proposed mining activities and the domestic socioeconomic effects of construction and operation of the associated facilities, including waste characteristics and toxicity;
(3) Any proposed mitigation measures to avoid or minimize adverse impacts on the environment;
(4) A certificate of consistency with the federally approved State coastal zone management program, where applicable; and
(5) Alternative sites and technologies considered by the lessee and the reasons why they were not chosen.
(s) Any other information needed for technical evaluation of the proposed activities and for the evaluation of potential impacts on the environment.
§ 282.25
Plan modification.
Approved Delineation, Testing, and Mining Plans may be modified upon the Director's approval of the changes proposed. When circumstances warrant, the Director may direct the lessee to modify an approved plan to adjust to changed conditions. If the lessee requests the change, the lessee shall submit a detailed, written statement of the proposed modifications, potential, impacts, and the justification for the proposed changes. Revision of an approved plan whether initiated by the lessee or ordered by the Director shall be submitted to the Director for approval. When the Director determines that a proposed revision could result in significant change in the impacts previously identified and evaluated or requires additional permits, the proposed plan revision shall be subject to the applicable review and approval procedures of §§ 282.21, 282.22, 282.23, and 282.24 of this part.
§ 282.26
Contingency Plan.
(a) When required by the Director, a lessee shall include a Contingency Plan as part of its request for approval of a Delineation, Testing, or Mining Plan. The Contingency Plan shall comply with the requirements of § 282.28(e) of this part.
(b) The Director may order or the lessee may request the Director's approval of a modification of the Contingency Plan when such a change is necessary to reflect any new information concerning the nature, magnitude, and significance of potential equipment or procedural failures or the effectiveness of the corrective actions described in the Contingency Plan.
§ 282.27
Conduct of operations.
(a) The lessee shall conduct all exploration, testing, development, and production activities and other operations in a safe and workmanlike manner and shall maintain equipment in a manner which assures the protection of the lease and its improvements, the health and safety of all persons, and the conservation of property, and the environment.
(b) Nothing in this part shall preclude the use of new or alternative technologies, techniques, procedures, equipment, or activities, other than those prescribed in the regulations of this part, if such other technologies, techniques, procedures, equipment, or activities afford a degree of protection, safety, and performance equal to or better than that intended to be achieved by the regulations of this part, provided the lessee obtains the written approval of the Director prior to the use of such new or alternative technologies, techniques, procedures, equipment, or activities.
(c) The lessee shall immediately notify the Director when there is a death or serious injury; fire, explosion, or other hazardous event which threatens damage to life, a mineral deposit, or equipment; spills of oil, chemical reagents, or other liquid pollutants which could cause pollution; or damage to aquatic life or the environment associated with operations on the lease. As soon as practical, the lessee shall file a detailed report on the event and action(s) taken to control the situation and to mitigate any further damage.
(d)(1) Lessees shall provide means, at all reasonable hours either day or night, for the Director to inspect or investigate the conditions of the operation and to determine whether applicable regulations; terms and conditions of the lease; and the requirements of the approved Delineation, Testing, or Mining Plan are being met.
(2) A lessee shall, on request by the Director, furnish food, quarters, and transportation for MMS representatives to inspect its facilities. Upon request, the lessee will be reimbursed by the United States for the actual costs which it incurs as a result of its providing food, quarters, and transportation for an MMS representative's stay of more than 10 hours. Request for reimbursement must be submitted within 60 days following the cost being incurred.
(e) Mining and processing vessels, platforms, structures, artificial islands, and mobile drilling units which have helicopter landing facilities shall be identified with at least one sign using letters and figures not less than 12 inches in height. Signs for structures without helicopter landing facilities shall be identified with at least one sign using letters and figures not less than 3 inches in height. Signs shall be affixed at a location that is visible to approaching traffic and shall contain the following information which may be abbreviated:
(1) Name of the lease operator;
(2) The area designation based on Official OCS Protraction Diagrams;
(3) The block number in which the facility is located; and
(4) Vessel, platform, structure, or rig name.
(f)(1) Drilling.(i) When drilling on lands valuable or potentially valuable for oil and gas or geopressured or geothermal resources, drilling equipment shall be equipped with blowout prevention and control devices acceptable to the Director before penetrating more than 500 feet unless a different depth is specified in advance by the Director.
(ii) In cases where the Director determines that there is sufficient liklihood of encountering pressurized hydrocarbons, the Director may require that the lessee comply with all or portions of the requirements in part 250, subpart D, of this title.
(iii) Before drilling any hole which may penetrate an aquifer, the lessee shall follow the procedures included in the approved plan for the penetration and isolation of the aquifer during the drilling operation, during use of the hole, and for subsequent abandonment of the hole.
(iv) Cuttings from holes drilled on the lease shall be disposed of and monitored in accordance with the approved plan.
(v) The use of muds in drilling holes on the lease and their subsequent disposition shall be according to the approved plan.
(2) All drill holes which are susceptible to logging shall be logged, and the lessee shall prepare a detailed lithologic log of each drill hole. Drill holes which are drilled deeper than 500 feet shall be drilled in a manner which permits logging. Copies of logs of cores and cuttings and all in-hole surveys such as electronic logs, gamma ray logs, neutron density logs, and sonic logs shall be provided to the Director.
(3) Drill holes for exploration, testing, development, or production shall be properly plugged and abandoned to the satisfaction of the Director in accordance with the approved plan and in such a manner as to protect the surface and not endanger any operation; any freshwater aquifer; or deposit of oil, gas, or other mineral substance.
(g) The use of explosives on the lease shall be in accordance with the approved plan.
(h)(1) Any equipment placed on the seabed shall be designed to allow its recovery and removal upon abandonment of leasehold activities.
(2) Disposal of equipment, cables, chains, containers, or other materials into the ocean is prohibited.
(3) Materials, equipment, tools, containers, and other items used on the OCS which are of such shape or configuration that they are likely to snag or damage fishing devices shall be handled and marked as follows:
(i) All loose materials, small tools, and other small objects shall be kept in a suitable storage area or a marked container when not in use or in a marked container before transport over OCS waters;
(ii) All cable, chain, or wire segments shall be recovered after use and securely stored;
(iii) Skid-mounted equipment, portable containers, spools or reels, and drums shall be marked with the owner's name prior to use or transport over OCS waters; and
(iv) All markings must clearly identify the owner and must be durable enough to resist the effects of the environmental conditions to which they are exposed.
(4) Any equipment or material described in paragraphs (h)(2), (h)(3)(ii), and (h)(3)(iii) of this section that is lost overboard shall be recorded on the daily operations report of the facility and reported to the Director and to the U.S. Coast Guard.
(i) Any bulk sampling or testing that is necessary to be conducted prior to submission of a Mining Plan shall be in accordance with an approved Testing Plan. The sale of any OCS minerals acquired under an approved Testing Plan shall be subject to the payment of the royalty specified in the lease to the United States.
(j) Installations and structures.(1) The lessee shall design, fabricate, install, use, inspect, and maintain all installations and structures, including platforms on the OCS, to assure the structural integrity of all installations and structures for the safe conduct of exploration, testing, mining, and processing activities considering the specific environmental conditions at the location of the installation or structure.
(2) All fixed or bottom-founded platforms or other structures, e.g., artificial islands shall be designed, fabricated, installed, inspected, and maintained in accordance with the provisions of part 250, subpart I, of this title.
(k) The lessee shall not produce any OCS mineral until the method of measurement and the procedures for product valuation have been instituted in accordance with the approved Testing or Mining Plan. The lessee shall enter the weight or quantity and quality of each mineral produced in accordance with § 282.29 of this title.
(l) The lessee shall conduct OCS mineral processing operations in accordance with the approved Testing or Mining Plan and use due diligence in the reduction, concentration, or separation of mineral substances by mechanical or chemical processes, by evaporation, or other means, so that the percentage of concentrates or other mineral substances are recovered in accordance with the practices approved in the Testing or Mining Plan.
(m) No material shall be discharged or disposed of except in accordance with the approved disposal practice and procedures contained in the approved Delineation, Testing, or Mining Plan.
§ 282.28
Environmental protection measures.
(a) Exploration, testing, development, production, and processing activities proposed to be conducted under a lease will only be approved by the Director upon the determination that the adverse impacts of the proposed activities can be avoided, minimized, or otherwise mitigated. The Director shall take into account the information contained in the sale-specific environmental evaluation prepared in association with the lease offering as well as the site- and operational-specific environmental evaluations prepared in association with the review and evaluation of the approved Delineation, Testing, or Mining Plan. The Director's review of the air quality consequences of proposed OCS activities will follow the practices and procedures specified in §§ 250.194, 250.218, 250.249, and 250.303 of this title.
(b) If the baseline data available are judged by the Director to be inadequate to support an environmental evaluation of a proposed Delineation, Testing, or Mining Plan, the Director may require the lessee to collect additional environmental baseline data prior to the approval of the activities proposed.
(c)(1) The lessee shall monitor activities in a manner that develops the data and information necessary to enable the Director to assess the impacts of exploration, testing, mining, and processing activities on the environment on and off the lease; develop and evaluate methods for mitigating adverse environmental effects; validate assessments made in previous environmental evaluations; and ensure compliance with lease and other requirements for the protection of the environment.
(2) Monitoring of environmental effects shall include determination of the spatial and temporal environmental changes induced by the exploration, testing, development, production, and processing activities on the flora and fauna of the sea surface, the water column, and/or the seafloor.
(3) The Director may place observers onboard exploration, testing, mining, and processing vessels; installations; or structures to ensure that the provisions of the lease, the approved plan, and these regulations are followed and to evaluate the effectiveness of the approved monitoring and mitigation practices and procedures in protecting the environment.
(4) The Director may order or the lessee may request a modification of the approved monitoring program prior to the startup of testing activities or commercial-scale recovery, and at other appropriate times as necessary, to reflect accurately the proposed operations or to incorporate the results of recent research or improved monitoring techniques.
(5) When prototype test mining is proposed, the lessee shall include a monitoring strategy for assessing the impacts of the testing activities and for developing a strategy for monitoring commercial-scale recovery and mitigating the impacts of commercial-scale recovery more effectively. At a minimum, the proposed monitoring activities shall address specific concerns expressed in the lease-sale environmental analysis.
(6) When required, the monitoring plan shall specify:
(i) The sampling techniques and procedures to be used to acquire the needed data and information;
(ii) The format to be used in analysis and presentation of the data and information;
(iii) The equipment, techniques, and procedures to be used in carrying out the monitoring program; and
(iv) The name and qualifications of person(s) designated to be responsible for carrying out the environmental monitoring.
(d) Lessees shall develop and conduct their operations in a manner designed to avoid, minimize, or otherwise mitigate environmental impacts and to demonstrate the effectiveness of efforts to that end. Based upon results of the monitoring program, the Director may specify particular procedures for mitigating environmental impacts.
(e) In the event that equipment or procedural failure might result in significant additional damage to the environment, the lessee shall submit a Contingency Plan which specifies the procedures to be followed to institute corrective actions in response to such a failure and to minimize adverse impacts on the environment. Such procedures shall be designed for the site and mining activities described in the approved Delineation, Testing, or Mining Plan.
[54 FR 2067, Jan. 18, 1989; 64 FR 9066, Feb. 24, 1999, as amended at 64 FR 72795, Dec. 28, 1999; 70 FR 51519, Aug. 30, 2005]
§ 282.29
Reports and records.
(a) A report of the amount and value of each OCS mineral produced from each lease shall be made by the payor for the lease for each calendar month, beginning with the month in which approved testing, development, or production activities are initiated and shall be filed in duplicate with the Director on or before the 20th day of the succeeding month, unless an extension of time for the filing of such report is granted by the Director. The report shall disclose accurately and in detail all operations conducted during each month and present a general summary of the status of leasehold activities. The report shall be submitted each month until the lease is terminated or relinquished unless the Director authorizes omission of the report during an approved suspension of production. The report shall show for each calendar month the location of each mining and processing activity; the number of days operations were conducted; the identity, quantity, quality, and value of each OCS mineral produced, sold, transferred, used or otherwise disposed of; identity, quantity, and quality of an inventory maintained prior to the point of royalty determination; and other information as may be required by the Director.
(b) The lessee shall submit a status report on exploration and/or testing activities under an approved Delineation or Testing Plan to the Director within 30 days of the close of each calendar quarter which shall include:
(1) A summary of activities conducted;
(2) A listing of all geophysical and geochemical data acquired and developed such as acoustic or seismic profiling records;
(3) A map showing location of holes drilled and where bottom samples were taken; and
(4) Identification of samples analyzed.
(c) Each lessee shall submit to the Director a report of exploration and/or testing activities within 3 months after the completion of operations. The final report of exploration and/or testing activities conducted on the lease shall include:
(1) A description of work performed;
(2) Charts, maps, or plats depicting the area and leases in which activities were conducted specifically identifying the lines of geophysical traverses and/or the locations where geological activity was conducted and/or the locations of other exploration and testing activities;
(3) The dates on which the actual operations were performed;
(4) A narrative summary of any mineral occurrences; environmental hazards; and effects of the activities on the environment, aquatic life, archaeological resources, or other uses and users of the area in which the activities were conducted;
(5) Such other descriptions of the activities conducted as may be specified by the Director; and
(6) Records of all samples from core drilling or other tests made on the lease. The records shall be in such form that the location and direction of the samples can be accurately located on a map. The records shall include logs of all strata penetrated and conditions encountered, such as minerals, water, gas, or unusual conditions, and copies of analyses of all samples analyzed.
(d) The lessee shall report the results of environmental monitoring activities required in § 282.28 of this part and shall submit such other environmental data as the Director may require to conform with the requirements of these regulations.
(e)(1) All maps shall be appropriately marked with reference to official lease boundaries and elevations marked with reference to sea level. When required by the Director, vertical projections and cross sections shall accompany plan views. The maps shall be kept current and submitted to the Director annually, or more often when required by the Director. The accuracy of maps furnished shall be certified by a professional engineer or land surveyor.
(2) The lessee shall prepare such maps of the leased lands as are necessary to show the geological conditions as determined from G&G surveys, bottom sampling, drill holes, trenching, dredging, or mining. All excavations shall be shown in such manner that the volume of OCS minerals produced during a royalty period can be accurately ascertained.
(f) Any lessee who acquires rock, mineral, and core samples under a lease shall keep a representative split of each geological sample and a quarter longitudinal segment of each core for 5 years during which time the samples shall be available for inspection at the convenience of the Director who may take cuts of such cores, cuttings, and samples.
(g)(1) The lessee shall keep all original data and information available for inspection or duplication, by the Director at the expense of the lessor, as long as the lease continues in force. Should the lessee choose to dispose of original data and information once the lease has expired, said data and information shall be offered to the lessor free of costs and shall, if accepted, become the property of the lessor.
(2) Navigation tapes showing the location(s) where samples were taken and test drilling conducted shall be retained for as long as the lease continues in force.
(h) Lessees shall maintain records in which will be kept an accurate account of all ore and rock mined; all ore put through a mill; all mineral products produced; all ore and mineral products sold, transferred, used, or otherwise disposed of and to whom sold or transferred, and the inventory weight, assay value, moisture content, base sales price, dates, penalties, and price received. The percentage of each of the mineral products recovered and the percentages lost shall be shown. The records associated with activities on a lease shall be available to the Director for auditing.
(i) When special forms or reports other than those referred to in the regulations in this part may be necessary, instructions for the filing of such forms or reports will be given by the Director.
§ 282.30
Right of use and easement.
(a) A right of use and easement that includes any area subject to a lease issued or maintained under the Act shall be granted only after the lessee has been notified by the requestor and afforded the opportunity to comment on the request. A holder of a right under a right of use and easement shall exercise that right in accordance with the requirements of the regulations in this part. A right of use and easement shall be exercised only in a manner which does not interfere unreasonably with operations of any lessee on its lease.
(b) Once a right of use and easement has been exercised, the right shall continue, beyond the termination of any lease on which it may be situated, as long as it is demonstrated to the Director that the right of use and easement is being exercised by the holder of the right and that the right of use and easement continues to serve the purpose specified in the grant. If the right of use and easement extends beyond the termination of any lease on which the right may be situated or if it is situated on an unleased portion of the OCS, the rights of all subsequent lessees shall be subject to such right. Upon termination of a right of use and easement, the holder of the right shall abandon the premises in the same manner that a lessee abandons activities on a lease to the satisfaction of the Director.
§ 282.31
Suspension of production or other operations.
A lessee may submit a request for a suspension of production or other operations. The request shall include justification for granting the requested suspension, a schedule of work leading to the initiation or restoration of production or other operations, and any other information the Director may require.

Subpart D—Payments
§ 282.40
Bonds.
(a) Pursuant to the requirements for a bond in § 281.33 of this title, prior to the commencement of any activity on a lease, the lessee shall submit a surety or personal bond to cover the lessee's royalty and other obligations under the lease as specified in this section.
(b) All bonds furnished by a lessee or operator must be in a form approved by the Associate Director for Offshore Minerals Management. A single copy of the required form is to be executed by the principal or, in the case of surety bonds, by both the principal and an acceptable surety.
(c) Only those surety bonds issued by qualified surety companies approved by the Department of the Treasury shall be accepted. (See Department of Treasury Circular No. 570 and any supplemental or replacement circulars.)
(d) Personal bonds shall be accompanied by a cashier's check, certified check, or negotiable U.S. Treasury bonds of an equal value to the amount specified in the bond. Negotiable Treasury bonds shall be accompanied by a proper conveyance of full authority to the Director to sell such securities in case of default in the performance of the terms and conditions of the lease.
(e) A bond in the minimum amount of $50,000 to cover the lessee's obligations under the lease shall be submitted prior to the commencement of any activity on a leasehold. A $50,000 bond shall not be required on a lease if the lessee already maintains or furnishes a $300,000 bond conditioned on compliance with the terms of leases for OCS minerals other than oil, gas, and sulphur held by the lessee on the OCS for the area in which the lease is located. A bond submitted pursuant to § 256.58(a) of this chapter may be amended to include the aforementioned condition for compliance. Prior to approval of a Delineation, Testing, or Mining Plan, the bond amount shall be adjusted, if appropriate, to cover the operations and activities described in the proposed plan.
(f) For the purposes of this section there are three areas:
(1) The Gulf of Mexico and the area offshore the Atlantic Ocean;
(2) The area offshore the Pacific Coast States of California, Oregon, Washington, and Hawaii; and
(3) The area offshore the coast of Alaska.
(g) A separate bond shall be required for each area. An operator's bond may be submitted for a specific lease(s) in the same amount as the lessee's bond(s) applicable to the lease(s) involved.
(h) Where, upon a default, the surety makes a payment to the United States of an obligation incurred under a lease, the face amount of the surety bond and the surety's liability thereunder shall be reduced by the amount of such payment.
(i) After default, the principal shall, within 6 months after notice or within such shorter period as may be fixed by the Director, either post a new bond or increase the existing bond to the amount previously held. In lieu thereof, the principal may, within that time, file separate or substitute bonds for each lease. Failure to meet these requirements may result in a suspension of operations including production on leases covered by such bonds.
(j) The Director shall not consent to termination of the period of liability of any bond unless an acceptable alternative bond has been filed or until all the terms and conditions of the lease covered by the bond have been met.
[54 FR 2067, Jan. 18, 1989, as amended at 62 FR 27960, May 22, 1997; 73 FR 20172, Apr. 15, 2008]
§ 282.41
Method of royalty calculation.
In the event that the provisions of royalty management regulations do not apply to the specific commodities produced under regulations in this part, the lessee shall comply with procedures specified in the leasing notice.
§ 282.42
Payments.
Rentals, royalties, and other payments due the Federal Government on leases for OCS minerals shall be paid and reports submitted by the payor for a lease in accordance with § 281.26 of this title.

Subpart E—Appeals
§ 282.50
Appeals.
See 30 CFR part 290 for instructions on how to appeal any order or decision that we issue under this part.
[65 FR 3857, Jan. 25, 2000]

SUBCHAPTER C—APPEALS
Pt. 290

PART 290—APPEAL PROCEDURES

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

Subpart B—Minerals Revenue Management Appeal Procedures
290.100
What is the purpose of this subpart?
290.101
What leases are subject to this subpart?
290.102
What definitions apply to this subpart?
290.103
Who may file an appeal?
290.104
What may I not appeal under this subpart?
290.105
How do I appeal an order?
290.106
How do lessees join a designee's appeal and how does joinder affect the appeal?
290.107
Where are the rules concerning the effect of the Department not issuing a decision in my appeal within the statutory time frame?
290.108
How do I appeal to the IBLA?
290.109
How do I request an extension of time?
290.110
How do I exhaust administrative remedies?

Authority:
5 U.S.C. 301 et seq.; 25 U.S.C. 396, 396a-396g, 2107; 30 U.S.C. 189, 190, 359, 1023, 1701 et seq., 1751(a); 31 U.S.C. 3716, 9701; 43 U.S.C. 1334, 1801 et seq.; and 44 U.S.C. 3506(a).

Source:
64 FR 26257, May 13, 1999, unless otherwise noted.

Subpart A—Offshore Minerals Management Appeal Procedures
§ 290.1
What is the purpose of this subpart?
The purpose of this subpart is to explain the procedures for appeals of Minerals Management Service (MMS) Offshore Minerals Management (OMM) decisions and orders issued under subchapter B.
§ 290.2
Who may appeal?
If you are adversely affected by an OMM official's final decision or order issued under 30 CFR chapter II, subchapter B, you may appeal that decision or order to the Interior Board of Land Appeals (IBLA). Your appeal must conform with the procedures found in this subpart and 43 CFR part 4, subpart E. A request for reconsideration of an MMS decision concerning a lease bid, authorized in 30 CFR 256.47(e)(3) and 281.21(a)(1), or a deep water field determination, authorized in 30 CFR 203.79(a) and 30 CFR 260.110(d)(2), is not subject to the procedures found in this part.
§ 290.3
What is the time limit for filing an appeal?
You must file your appeal within 60 days after you receive OMM's final decision or order. The 60-day time period applies rather than the time period provided in 43 CFR 4.411(a). A decision or order is received on the date you sign a receipt confirming delivery or, if there is no receipt, the date otherwise documented.
§ 290.4
How do I file an appeal?
For your appeal to be filed, MMS must receive all of the following within 60 days after you receive the decision or order:
(a) A written Notice of Appeal together with a copy of the decision or order you are appealing in the office of the OMM officer that issued the decision or order. You cannot extend the 60-day period for that office to receive your Notice of Appeal; and
(b) A nonrefundable processing fee of $150 paid with the Notice of Appeal.
(1) Identify the order you are appealing on the check or other form of payment you use to pay the processing fee.
(2) You cannot extend the 60-day period for payment of the processing fee.
(3) You must pay the processing fee to MMS following the requirements for making payments found in 30 CFR 218.51. You are not required to use Electronic Funds Transfer (EFT) for these payments.
§ 290.5
Can I obtain an extension for filing my Notice of Appeal?
You cannot obtain an extension of time to file the Notice of Appeal. See 43 CFR 4.411(c).
§ 290.6
Are informal resolutions permitted?
(a) You may seek informal resolution with the issuing officer's next level supervisor during the 60-day period established in § 290.3.
(b) Nothing in this subpart precludes resolution by settlement of any appeal or matter pending in the administrative process after the 60-day period established in § 290.3.
§ 290.7
Do I have to comply with the decision or order while my appeal is pending?
(a) The decision or order is effective during the 60-day period for filing an appeal under § 290.3 unless:
(1) OMM notifies you that the decision or order, or some portion of it, is suspended during this period because there is no likelihood of immediate and irreparable harm to human life, the environment, any mineral deposit, or property; or
(2) You post a surety bond under 30 CFR 250.1409 pending the appeal challenging an order to pay a civil penalty.
(b) This section applies rather than 43 CFR 4.21(a) for appeals of OMM orders.
(c) After you file your appeal, IBLA may grant a stay of a decision or order under 43 CFR 4.21(b); however, a decision or order remains in effect until IBLA grants your request for a stay of the decision or order under appeal.
§ 290.8
How do I exhaust my administrative remedies?
(a) If you receive a decision or order issued under chapter II, subchapter B, you must appeal that decision or order to IBLA under 43 CFR part 4, subpart E to exhaust administrative remedies.
(b) This section does not apply if the Assistant Secretary for Land and Minerals Management or the IBLA makes a decision or order immediately effective notwithstanding an appeal.

Subpart B—Minerals Revenue Management Appeal Procedures
§ 290.100
What is the purpose of this subpart?
This subpart tells you how to appeal Minerals Management Service (MMS) or delegated State orders concerning reporting to the Minerals Revenue Management (MRM) and the payment of royalties and other payments due under leases subject to this subpart.
[71 FR 51752, Aug. 31, 2006]
§ 290.101
What leases are subject to this subpart?
This subpart applies to:
(a) All Federal mineral leases onshore and on the Outer Continental Shelf (OCS); and
(b) All federally-administered mineral leases on Indian tribal and individual Indian mineral owners' lands, regardless of the statutory authority under which the lease was issued or maintained.
§ 290.102
What definitions apply to this subpart?
Assessment means any fee or charge levied or imposed by the Secretary or a delegated State other than:
(1) The principal amount of any royalty, minimum royalty, rental, bonus, net profit share or proceed of sale;
(2) Any interest; or
(3) Any civil or criminal penalty.
Delegated State means a State to which MMS has delegated authority to perform royalty management functions under an agreement or agreements under regulations at 30 CFR part 227.
Designee means the person designated by a lessee under 30 CFR 218.52 to make all or part of the royalty or other payments due on a lease on the lessee's behalf.
IBLA means the Interior Board of Land Appeals.
Indian lessor means an Indian tribe or individual Indian mineral owner with a beneficial or restricted interest in a property that is subject to a lease issued or administered by the Secretary on behalf of the tribe or individual Indian mineral owner.
Lease means any agreement authorizing exploration for or extraction of any mineral, regardless of whether the instrument is expressly denominated as a “lease,” including any:
(1) Contract;
(2) Net profit share arrangement;
(3) Joint venture; or
(4) Agreement the Secretary approves under the Indian Mineral Development Act, 25 U.S.C. 2101 et seq.
Lessee means any person to whom the United States, or the United States on behalf of an Indian tribe or individual Indian mineral owner, issues a lease subject to this subpart, or any person to whom all or part of the lessee's interest or operating rights in a lease subject to this subpart has been assigned.
Notice of Order means the notice that MMS or a delegated State issues to a lessee that informs the lessee that MMS or the delegated State has issued an order to the lessee's designee.
Obligation means:
(1) A lessee's, designee's or payor's duty to:
(i) Deliver oil or gas royalty in kind; or
(ii) Make a lease-related payment, including royalty, minimum royalty, rental, bonus, net profit share, proceeds of sale, interest, penalty, civil penalty, or assessment; and
(2) The Secretary's duty to:
(i) Take oil or gas royalty-in-kind; or
(ii) Make a lease-related payment, refund, offset, or credit, including royalty, minimum royalty, rental, bonus, net profit share, proceeds of sale, or interest.
(3) The obligations identified in paragraphs (1)(i) and (2)(i) of this definition are nonmonetary obligations. The obligations identified in paragraphs (1)(ii) and (2)(ii), including the requirement to compute the amount of such obligations, are monetary obligations.
Order, for purposes of this subpart only, means any document issued by the MMS Director, MMS MRM, or a delegated state that contains mandatory[smc2] or ordering language that requires the recipient to do any of the following for any lease subject to this subpart: report, compute, or pay royalties or other obligations, report production, or provide other information.
(1) Order includes:
(i) An order to pay or to compute and pay; and
(ii) An MMS or delegated State decision to deny a lessee's, designee's, or payor's written request that asserts an obligation due the lessee, designee or payor.
(2) Order does not include:
(i) A non-binding request, information, or guidance, such as:
(A) Advice or guidance on how to report or pay, including a valuation determination, unless it contains mandatory or ordering language; and
(B) A policy determination;
(ii) A subpoena;
(iii) An order to pay that MMS issues to a refiner or other person involved in disposition of royalty taken in kind; or
(iv) A Notice of Noncompliance or a Notice of Civil Penalty issued under 30 U.S.C. 1719 and 30 CFR part 241, or a decision of an administrative law judge or of the IBLA following a hearing on the record on a Notice of Noncompliance or Notice of Civil Penalty.
Party means MMS, any person who files a Notice of Appeal, and any person who files a Notice of Joinder in an appeal under this subpart.
[64 FR 26257, May 13, 1999, as amended at 71 FR 51752, Aug. 31, 2006]
§ 290.103
Who may file an appeal?
(a) If you receive an order that adversely affects you or your lessee, you may appeal that order except as provided under § 290.104.
(b) If you are a lessee and you receive a Notice of Order, and if you contest the order, you may either appeal the order or join in your designee's appeal under § 290.106.
§ 290.104
What may I not appeal under this subpart?
You may not appeal:
(a) An action that is not an order, as defined in this subpart; or
(b) A determination of the surety amount or financial solvency under 30 CFR part 243, subparts B or C.
§ 290.105
How do I appeal an order?
(a) You may appeal an order to the Director, Minerals Management Service (MMS Director), by filing a Notice of Appeal in the office of the official issuing the order within 30 days from service of the order.
(1) Within the same 30-day period, you must file in the office of the official issuing the order a statement of reasons or written arguments or briefs that include the arguments on the facts or laws that you believe justify reversal or modification of the order.
(2) If you are a designee, when you file your Notice of Appeal you must serve your Notice of Appeal on the lessees for the leases in the order you appealed.
(b) You may not request and will not receive an extension of time for filing the Notice of Appeal.
(c) If the office of the official issuing the order does not receive the Notice of Appeal within the time provided in paragraph (a) of this section, the Notice of Appeal will be considered timely if the office of the official issuing the order receives:
(1) The Notice of Appeal not later than 10 days after the required filing date; and
(2) The officer with whom the Notice of Appeal must be filed determines that the Notice of Appeal was transmitted to the proper office before the filing deadline in paragraph (a) of this section.
(d) If the Notice of Appeal is filed after the grace period provided in paragraph (c) of this section and was not transmitted to the proper office before the filing deadline in paragraph (a) of this section, the MMS Director will not consider the Notice of Appeal and the case will be closed.
(e) The officer with whom the Notice of Appeal is filed will send the appeal and accompanying papers to the MMS Director.
(f) The MMS Director will review the record and render a decision in the case.
(g) If an order involves Indian leases, the Deputy Commissioner of Indian Affairs will exercise the functions vested in the MMS Director.
§ 290.106
How do lessees join a designee's appeal and how does joinder affect the appeal?
(a) If you are a lessee, and your designee files an appeal under § 290.103, you may join in that appeal within 30 days after you receive your designee's Notice of Appeal under § 290.105(a)(2) by filing a Notice of Joinder with the office or official that issued the order.
(b) If you join in an appeal under paragraph (a) of this section, you are deemed to appeal the order jointly with the designee, but the designee must fulfill all requirements imposed on appellants under this subpart and 43 CFR part 4, subparts E and J. You may not file submissions or pleadings separately from the designee.
(c) If you are a lessee and you neither appeal nor join in your designee's appeal under this section, your designee's actions with respect to the appeal and any decisions in the appeal bind you.
(d) If you are a designee and you decide to discontinue participation in the appeal, you must serve written notice within 30 days before the next submission or pleading is due on:
(1) All lessees who have joined in the appeal under paragraph (a) of this section;
(2) The office or officer with whom any subsequent submissions or pleadings must be filed, including the IBLA; and
(3) All other parties to the appeal.
(e) If you have joined in the appeal under paragraph (a) of this section, and if the designee notifies you under paragraph (d) of this section that it declines to further pursue the appeal, you become an appellant and must then meet all requirements of this subpart and 43 CFR part 4, subparts E and J, as the appellant.
§ 290.107
Where are the rules concerning the effect of the Department not issuing a decision in my appeal within the statutory time frame?
If your appeal involves monetary or nonmonetary obligations under Federal oil and gas leases, the rules concerning the effect of the Department not issuing a final decision in your appeal within the 33-month period prescribed under 30 U.S.C. 1724(h) are located in 43 CFR part 4, subpart J.
§ 290.108
How do I appeal to the IBLA?
Any party to a case adversely affected by a final decision of the MMS Director or the Deputy Commissioner of Indian Affairs under this subpart shall have a right of appeal to the IBLA under the procedures provided in 43 CFR part 4, subpart E.
§ 290.109
How do I request an extension of time?
(a) If you are a party to an appeal under this subpart, and you need additional time after the appeal commences under 43 CFR 4.904 for any purpose:
(1) You may obtain an extension of time under this section; and
(2) You must submit a written request for an extension of time to:
(i) The office or official with whom you must file a document before the required filing date; or
(ii) If you are not seeking an extension of time to file a document, to the office or official before whom the appeal is pending.
(b) If you are an appellant, and if your appeal involves monetary or nonmonetary obligations under Federal oil and gas leases, you must agree in writing in your request to extend the period in which the Department must issue a final decision in your appeal under 30 U.S.C. 1724(h) and 43 CFR 4.906, by the amount of time for which you are requesting an extension.
(c) If you are any other party to an appeal involving monetary or nonmonetary obligations under Federal oil and gas leases, the office or official with whom you must file the request may require you to submit a written agreement signed by the appellant to extend the period in which the Department must issue a final decision in the appeal under 43 CFR 4.906, by the amount of time for which you are requesting an extension.
(d) The office or official with whom you must file your request may decline any request for an extension of time.
(e) You must serve your request on all parties to the appeal.
§ 290.110
How do I exhaust administrative remedies?
(a) To exhaust administrative remedies, you must appeal an MMS Royalty Management Program (RMP) or delegated State order:
(1) To the MMS Director (or the Deputy Commissioner of Indian Affairs when Indian lands are involved); and
(2) Subsequently to the Interior Board of Land Appeals under 30 CFR part 290, subpart B, and 43 CFR part 4.
(b) This section does not apply if an order was made effective by:
(1) The Director;
(2) The Assistant Secretary for Land and Minerals Management;
(3) The Assistant Secretary for Indian Affairs; or
(4) The Interior Board of Land Appeals under 43 CFR part 4.
[64 FR 50753, Sept. 20, 1999]
Pt. 291

PART 291—OPEN AND NONDISCRIMINATORY ACCESS TO OIL AND GAS PIPELINES UNDER THE OUTER CONTINENTAL SHELF LANDS ACT
Sec.
291.1
What is MMS's authority to collect information?
291.100
What is the purpose of this part?
291.101
What definitions apply to this part?
291.102
May I call the MMS Hotline to informally resolve an allegation that open and nondiscriminatory access was denied?
291.103
May I use alternative dispute resolution to informally resolve an allegation that open and nondiscriminatory access was denied?
291.104
Who may file a complaint or a third-party brief?
291.105
What must a complaint contain?
291.106
How do I file a complaint?
291.107
How do I answer a complaint?
291.108
How do I pay the processing fee?
291.109
Can I ask for a fee waiver or a reduced processing fee?
291.110
Who may MMS require to produce information?
291.111
How does MMS treat the confidential information that I provide?
291.112
What process will MMS follow in rendering a decision on whether a grantee or transporter has provided open and nondiscriminatory access?
291.113
What actions may MMS take to remedy denial of open and nondiscriminatory access?
291.114
How do I appeal to the IBLA?
291.115
How do I exhaust administrative remedies?

Authority:
43 U.S.C. 1334, 31 U.S.C. 9701, section 342 of the Energy Policy Act of 2005.

Source:
73 FR 34640, June 18, 2008, unless otherwise noted.

Effective Date Note:
At 73 FR 34640, June 18, 2008, part 291 was added, effective Aug. 18, 2008.
§ 291.1
What is MMS's authority to collect information?
(a) The Office of Management and Budget (OMB) has approved the information collection requirements in this part under 44 U.S.C. 3501 et seq., and assigned OMB Control Number 1010-0172.
(b) An agency may not conduct or sponsor, and you are not required to respond to, a collection of information unless it displays a currently valid OMB control number.
(c) We use the information collected to determine whether or not the shipper has been denied open and nondiscriminatory access to Outer Continental Shelf (OCS) pipelines as sections of 5(e) and (f) of the OCS Lands Act (OCSLA) require.
(d) Respondents are companies that ship or transport oil and gas production across the OCS. Responses are required to obtain or retain benefits. We will protect information considered proprietary under applicable law.
(e) Send comments regarding any aspect of the collection of information under this part, including suggestions for reducing the burden, to the Information Collection Clearance Officer, Minerals Management Service, Mail Stop 4230, 1849 C Street, NW., Washington, DC 20240.
§ 291.100
What is the purpose of this part?
This part:
(a) Explains the procedures for filing a complaint with the Director, Minerals Management Service (MMS) alleging that a grantee or transporter has denied a shipper of production from the OCS open and nondiscriminatory access to a pipeline;
(b) Explains the procedures MMS will employ to determine whether violations of the requirements of the OCSLA have occurred, and to remedy any violations; and
(c) Provides for alternative informal means of resolving pipeline access disputes through either Hotline-assisted procedures or alternative dispute resolution (ADR).
§ 291.101
What definitions apply to this part?
As used in this part:
Accessory means a platform, a major subsea manifold, or similar subsea structure attached to a right-of-way (ROW) pipeline to support pump stations, compressors, manifolds, etc. The site used for an accessory is part of the pipeline ROW grant.
Appurtenance means equipment, device, apparatus, or other object attached to a horizontal component or riser. Examples include anodes, valves, flanges, fittings, umbilicals, subsea manifolds, templates, pipeline end modules (PLEMs), pipeline end terminals (PLETs), anode sleds, other sleds, and jumpers (other than jumpers connecting subsea wells to manifolds).
FERC pipeline means any pipeline within the jurisdiction of the Federal Energy Regulatory Commission (FERC) under the Natural Gas Act, 15 U.S.C. 717-717z, or the Interstate Commerce Act, 42 U.S.C. 7172(a) and (b).
Grantee means any person to whom MMS has issued an oil or gas pipeline permit, license, easement, right-of-way, or other grant of authority for transportation on or across the OCS under 30 CFR part 250, subpart J or 43 U.S.C. 1337(p), and any person who has an assignment of a permit, license, easement, right-of-way or other grant of authority, or who has an assignment of any rights subject to any of those grants of authority under 30 CFR part 250, subpart J or 43 U.S.C. 1337(p).
IBLA means the Interior Board of Land Appeals.
OCSLA pipeline means any oil or gas pipeline for which MMS has issued a permit, license, easement, right-of-way, or other grant of authority.
Outer Continental Shelf means all submerged lands lying seaward and outside of the area of lands beneath navigable waters as defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of which the subsoil and seabed appertain to the United States and are subject to its jurisdiction and control.
Party means any person who files a complaint, any person who files an answer, and MMS.
Person means an individual, corporation, government entity, partnership, association (including a trust or limited liability company), consortium, or joint venture (when established as a separate entity).
Pipeline is the piping, risers, accessories and appurtenances installed for transportation of oil and gas.
Serve means personally delivering a document to a person, or sending a document by U.S. mail or private delivery services that provide proof of delivery (such as return receipt requested) to a person.
Shipper means a person who contracts or wants to contract with a grantee or transporter to transport oil or gas through the grantee's or transporter's pipeline.
Transportation means, for purposes of this part only, the movement of oil or gas through an OCSLA pipeline.
Transporter means, for purposes of this part only, any person who owns or operates an OCSLA oil or gas pipeline.
§ 291.102
May I call the MMS Hotline to informally resolve an allegation that open and nondiscriminatory access was denied?
Before filing a complaint under § 291.106, you may attempt to informally resolve an allegation concerning open and nondiscriminatory access by calling the toll-free MMS Hotline at 1-888-232-1713.
(a) MMS Hotline staff will informally seek information needed to resolve the dispute. MMS Hotline staff will attempt to resolve disputes without litigation or other formal proceedings. The Hotline staff will not attempt to resolve matters that are before MMS or FERC in docketed proceedings.
(b) MMS Hotline staff may provide information to you and give informal oral advice. The advice given is not binding on MMS, the Department of the Interior (DOI), or any other person.
(c) To the extent permitted by law, the MMS Hotline staff will treat all information it obtains as non-public and confidential.
(d) You may call the MMS Hotline anonymously.
(e) If you contact the MMS Hotline, you may file a complaint under this part if discussions assisted by MMS Hotline staff are unsuccessful at resolving the matter.
(f) You may terminate use of the MMS Hotline procedure at any time.
§ 291.103
May I use alternative dispute resolution to informally resolve an allegation that open and nondiscriminatory access was denied?
You may ask to use ADR either before or after you file a complaint. To make a request, call the MMS at 1-888-232-1713 or write to us at the following address: Associate Director, Policy and Management Improvement, Minerals Management Service, 1849 C Street, NW., Mail Stop 4230, Washington, DC 20240-0001.
(a) You may request that ADR be administered by:
(1) A contracted ADR provider agreed to by all parties;
(2) The Department's Office of Collaborative Action and Dispute Resolution (CADR); or
(3) MMS staff trained in ADR and certified by the CADR.
(b) Each party must pay its respective share of all costs and fees associated with any contracted or Departmental ADR provider. For purposes of this section, MMS is not a party in an ADR proceeding.
§ 291.104
Who may file a complaint or a third-party brief?
(a) You may file a complaint under this subpart if you are a shipper and you believe that you have been denied open and nondiscriminatory access to an OCSLA pipeline that is not a FERC pipeline.
(b) Any person that believes its interests may be affected by precedents established by adjudication of complaints under this rule may submit a brief to MMS. The brief must be served following the procedure set out in 30 CFR 291.107. After considering the brief, it is within MMS's discretion as to whether MMS may:
(1) Address the brief in its decision;
(2) Not address the brief in its decision; or
(3) Include the submitter of the brief in the proceeding as a party.
§ 291.105
What must a complaint contain?
For purposes of this subpart, a complaint means a comprehensive written brief stating the legal and factual basis for the allegation that a shipper was denied open and nondiscriminatory access, together with supporting material. A complaint must:
(a) Clearly identify the action or inaction which is alleged to violate 43 U.S.C. 1334(e) or (f)(1)(A);
(b) Explain how the action or inaction violates 43 U.S.C. 1334(e) or (f)(1)(A);
(c) Explain how the action or inaction affects your interests, including practical, operational, or other non-financial impacts;
(d) Estimate any financial impact or burden;
(e) State the specific relief or remedy requested; and
(f) Include all documents that support the facts in your complaint including, but not limited to, contracts and any affidavits that may be necessary to support particular factual allegations.
§ 291.106
How do I file a complaint?
To file a complaint under this part, you must:
(a) File your complaint with the Director, Minerals Management Service at the following address: Director, Minerals Management Service, Attention: Policy and Management Improvement, 1849 C Street, NW., Mail Stop 4230, Washington, DC 20240-0001; and
(b) Include a nonrefundable processing fee of $7,500 under § 291.108(a) or a request for reduction or waiver of the fee under § 291.109(a); and
(c) Serve your complaint on all persons named in the complaint. If you make a claim under § 291.111 for confidentiality, serve the redacted copy and proposed form of a protective agreement on all persons named in the complaint.
(d) Complaints shall not be filed later than two (2) years from the time of the alleged access denial. If the complaint is filed later than two (2) years from the time of the alleged access denial, the MMS Director will not consider the complaint and the case will be closed.
§ 291.107
How do I answer a complaint?
(a) If you have been served a complaint under § 291.106, you must file an answer within 60 days of receiving the complaint. If you miss this deadline, MMS may disregard your answer. We consider your answer to be filed when the MMS Director receives it at the following address: Director, Minerals Management Service, Attention: Policy and Management Improvement, 1849 C Street, NW., Mail Stop 4230, Washington, DC 20240-0001.
(b) For purposes of this paragraph, an answer means a comprehensive written brief stating the legal and factual basis refuting the allegations in the complaint, together with supporting material. You must:
(1) Attach to your answer a copy of the complaint or reference the assigned MMS docket number (you may obtain the docket number by calling the Policy and Management Improvement Office at (202) 208-2622);
(2) Explain in your answer why the action or inaction alleged in the complaint does not violate 43 U.S.C. 1334(e) or (f)(1)(A);
(3) Include with your answer all documents in your possession or that you can otherwise obtain that support the facts in your answer including, but not limited to, contracts and any affidavits that may be necessary to support particular factual allegations; and
(4) Provide a copy of your answer to all parties named in the complaint including the complainant. If you make a claim under § 291.111 for confidentiality, serve the redacted copy and proposed form of a protective agreement to all parties named in the complaint, including the complainant.
§ 291.108
How do I pay the processing fee?
(a) You must pay the processing fee electronically through Pay.Gov. The Pay.Gov Web site may be accessed through links on the MMS Offshore Web site at: http://www.mms.gov/offshore/homepage (on drop-down topic list) or directly through Pay.Gov at: https://www.pay.gov/paygov/.
(b) You must include with the payment:
(1) Your taxpayer identification number;
(2) Your payor identification number, if applicable; and
(3) The complaint caption, or any other applicable identification of the complaint you are filing.
§ 291.109
Can I ask for a fee waiver or a reduced processing fee?
(a) MMS may grant a fee waiver or fee reduction in extraordinary circumstances. You may request a waiver or reduction of your fee by:
(1) Sending a written request to the MMS Policy and Management Improvement Office when you file your complaint; and
(2) Demonstrating in your request that you are unable to pay the fee or that payment of the full fee would impose an undue hardship upon you.
(b) The MMS Policy and Management Improvement Office will send you a written decision granting or denying your request for a fee waiver or a fee reduction.
(1) If we grant your request for a fee reduction, you must pay the reduced processing fee within 30 days of the date you receive our decision.
(2) If we deny your request, you must pay the entire processing fee within 30 days of the date you receive the decision.
(3) MMS's decision granting or denying a fee waiver or reduction is final for the Department.
§ 291.110
Who may MMS require to produce information?
(a) MMS may require any lessee, operator of a lease or unit, shipper, grantee, or transporter to provide information that MMS believes is necessary to make a decision on whether open access or nondiscriminatory access was denied.
(b) If you are a party and fail to provide information MMS requires under paragraph (a) of this section, MMS may:
(1) Assess civil penalties under 30 CFR part 250, subpart N;
(2) Dismiss your complaint or consider your answer incomplete; or
(3) Presume the required information is adverse to you on the factual issues to which the information is relevant.
(c) If you are not a party to a complaint and fail to provide information MMS requires under paragraph (a) of this section, MMS may assess civil penalties under 30 CFR part 250, subpart N.
§ 291.111
How does MMS treat the confidential information I provide?
(a) Any person who provides documents under this part in response to a request by MMS to inform a decision on whether open access or nondiscriminatory access was denied may claim that some or all of the information contained in a particular document is confidential. If you claim confidential treatment, then when you provide the document to MMS you must:
(1) Provide a complete unredacted copy of the document and indicate on that copy that you are making a request for confidential treatment for some or all of the information in the document.
(2) Provide a statement specifying the specific statutory justification for nondisclosure of the information for which you claim confidential treatment. General claims of confidentiality are not sufficient. You must furnish sufficient information for MMS to make an informed decision on the request for confidential treatment.
(3) Provide a second copy of the document from which you have redacted the information for which you wish to claim confidential treatment. If you do not submit a second copy of the document with the confidential information redacted, MMS may assume that there is no objection to public disclosure of the document in its entirety.
(b) In making data and information you submit available to the public, MMS will not disclose documents exempt from disclosure under the Freedom of Information Act (5 U.S.C. 552) and will follow the procedures set forth in the implementing regulations at 43 CFR Part 2 to give submitters an opportunity to object to disclosure.
(c) MMS retains the right to make the determination with regard to any claim of confidentiality. MMS will notify you of its decision to deny a claim, in whole or in part, and, to the extent permitted by law, will give you an opportunity to respond at least 10 days before its public disclosure.
§ 291.112
What process will MMS follow in rendering a decision on whether a grantee or transporter has provided open and nondiscriminatory access?
MMS will begin processing a complaint upon receipt of a processing fee or granting a waiver of the fee. The MMS Director will review the complaint, answer, and other information, and will serve all parties with a written decision that:
(a) Makes findings of fact and conclusions of law; and
(b) Renders a decision determining whether the complainant has been denied open and nondiscriminatory access.
§ 291.113
What actions may MMS take to remedy denial of open and nondiscriminatory access?
If the MMS Director's decision under § 291.112 determines that the grantee or transporter has not provided open access or nondiscriminatory access, then the decision will describe the actions MMS will take to require the grantee or transporter to remedy the denial of open access or nondiscriminatory access. The remedies MMS would require must be consistent with MMS's statutory authority, regulations, and any limits thereon due to Congressional delegations to other agencies. Actions MMS may take include, but are not limited to:
(a) Ordering grantees and transporters to provide open and nondiscriminatory access to the complainant;
(b) Assessing civil penalties of up to $10,000 per day under 30 CFR part 250, subpart N, for failure to comply with an MMS order to provide open access or nondiscriminatory access. Penalties will begin to accrue 60 days after the grantee or transporter receives the order to provide open and nondiscriminatory access if it has not provided such access by that time. However, if MMS determines that requiring the construction of facilities would be an appropriate remedy under the OCSLA, penalties will begin to accrue 10 days after conclusion of diligent construction of needed facilities or 60 days after the grantee or transporter receives the order to provide open and nondiscriminatory access, whichever is later, if it has not provided such access by that time;
(c) Requesting the Attorney General to institute a civil action in the appropriate United States District Court under 43 U.S.C. 1350(a) for a temporary restraining order, injunction, or other appropriate remedy to enforce the open and nondiscriminatory access requirements of 43 U.S.C. 1334(e) and (f)(1)(A); or
(d) Initiating a proceeding to forfeit the right-of-way grant under 43 U.S.C. 1334(e).
§ 291.114
How do I appeal to the IBLA?
Any party, except as provided in § 291.115(b), adversely affected by a decision of the MMS Director under this part may appeal to the Interior Board of Land Appeals (IBLA) under the procedures in 43 CFR part 4, subpart E.
§ 291.115
How do I exhaust administrative remedies?
(a) If the MMS Director issues a decision under this part but does not expressly make the decision effective upon issuance, you must appeal the decision to the IBLA under 43 CFR part 4 to exhaust administrative remedies. Such decision will not be effective during the time in which a person adversely affected by the MMS Director's decision may file a notice of appeal with the IBLA, and the timely filing of a notice of appeal will suspend the effect of the decision pending the decision on appeal.
(b) This section does not apply if a decision was made effective by:
(1) The MMS Director; or
(2) The Assistant Secretary for Land and Minerals Management.
30 CFR Ch. III (7-1-08 Edition)
Board of Surface Mining, Reclamation Appeals, Interior

CHAPTER III—BOARD OF SURFACE MINING AND RECLAMATION APPEALS, DEPARTMENT OF THE INTERIOR
Part
Page
301
Procedures under Surface Mining Control and Reclamation Act of 1977
597
Pt. 301

PART 301—PROCEDURES UNDER SURFACE MINING CONTROL AND RECLAMATION ACT OF 1977

Authority:
Sec. 201, Pub. L. 95-87, 91 Stat. 445, 30 U.S.C. 1201 et seq.
§ 301.1
Cross reference.
For special rules applicable to hearings, appeals, and other review procedures relating to surface mining control and reclamation within the jurisdiction of administrative law judges and the Interior Board of Surface Mining and Reclamation Appeals, Office of Hearings and Appeals, see Subpart L of part 4 of subtitle A—Office of the Secretary of the Interior, of title 43 CFR. Subpart A of part 4 and all of the general rules in subpart B of part 4 not inconsistent with the special rules in subpart L of part 4 are also applicable to such hearings, appeals and other review proceedings.
[43 FR 41974, Sept. 19, 1978]
30 CFR Ch. IV (7-1-08 Edition)
Geological Survey, Interior

CHAPTER IV—GEOLOGICAL SURVEY, DEPARTMENT OF THE INTERIOR
Part
Page
401
State Water Research Institute Program
601
402
Water-Resources Research Program and the Water-Resources Technology Development Program
606
Pt. 401

PART 401—STATE WATER RESEARCH INSTITUTE PROGRAM

Subpart A—General
Sec.
401.1
Purpose.
401.2
Delegation of authority.
401.3
Definitions.
401.4
Information collection.
401.5
[Reserved]

Subpart B—Designation of Institutes; Institute Programs
401.6
Designation of institutes.
401.7
Programs of institutes.
401.8-401.10
[Reserved]

Subpart C—Application and Management Procedures
401.11
Applications for grants.
401.12
Program management.
401.13-401.18
[Reserved]

Subpart D—Reporting
401.19
Reporting procedures.
401.20-401.25
[Reserved]

Subpart E—Evaluation
401.26
Evaluation of institutes.

Authority:
42 U.S.C. 10303.

Source:
50 FR 23114, May 31, 1985, unless otherwise noted.

Subpart A—General
§ 401.1
Purpose.
The regulations in this part are issued pursuant to title I of the Water Research Act of 1984 (Pub. L. 98-242, 98 Stat. 97) which authorizes appropriations to, and confers authority upon, the Secretary of the Interior to promote a national program of water-resources research.
§ 401.2
Delegation of authority.
The State Water Research Institute Program, as authorized by section 104 of the Act, has been established as a component of the U.S. Geological Survey (USGS). Secretary of the Interior has delegated to the Director of the USGS authority to take the actions and make the determinations that, under the Act, are the responsibility of the Secretary.
§ 401.3
Definitions.
Act means the Water Resources Research Act of 1984 (Pub. L. 98-242, 98 Stat. 97).
Fiscal year means a 12-month period ending on September 30.
Director means the Director of the USGS or a designee.
Grant means the funds made available to an institute in a particular fiscal year pursuant to section 104 of the Act and the regulations in this chapter.
Grantee means the college or university at which an institute is established.
Granting agency means the USGS.
Institute means a water resources research institute, center, or equivalent agency established in accordance with Title I of the Act.
Region means any grouping of two or more institutes mutually chosen by themselves to reflect a commonality of water-resources problems.
Scientists means individuals engaged in any professional discipline, including the life, physical or social sciences, and engineers.
Secretary means the Secretary of the Interior or a designee.
State means each of the 50 States, the Commonwealth of Puerto Rico, the Virgin Islands, the District of Columbia, Guam, American Samoa, the Commonwealth of the Mariana Islands, and the Federated States of Micronesia.
[50 FR 23114, May 31, 1985, as amended at 58 FR 27204, May 7, 1993]
§ 401.4
Information collection.
(a) The information collection requirements contained in sections 401.11 and 401.19 have been approved by the Office of Management and Budget under 44 U.S.C. 3501 et seq. and assigned clearance number 1028-0044. The information will be used to support water related research and provide performance reports on accomplishments achieved under Pub. L. 98-242, 98 Stat. 97 (42 U.S.C. 10303). This information allows the agency to determine compliance with the objectives and criteria of the grant programs. Response is mandatory in accordance with 30 CFR 401.11 and 401.19.
(b) Public reporting burden for the collection of information is estimated to average 84 hours per response, including the time for reviewing instructions, searching existing data sources, gathering and maintaining the data needed, and completing and reviewing the collection of information. Send comments regarding this burden estimate, or any other suggestions for reducing the burden, to Paperwork Management Officer, U.S. Geological Survey, Paperwork Management Section MS 208, Reston, Virginia 22092 and the Office of Management and Budget, Paperwork Reduction Project (1028-0044), Washington, DC 20503.
[58 FR 27204, May 7, 1993]
§ 401.5
[Reserved]

Subpart B—Designation of Institutes; Institute Programs
§ 401.6
Designation of institutes.
(a) As a condition of recognition as an established institute under the provisions of this chapter, each institute shall provide to the Director written evidence that it conforms to the requirements of subsection 104(a) of the Act, in that:
(1) The institute is established at the college or university in the State that was established in accordance with the Act of July 21, 1862 (12 Stat. 503; 7 U.S.C. 301ff), i.e., a “land-grant” institution, or;
(2) If established at some other institution, the institute is at a college or university that has been designated by act of the legislature for the purposes of the Act, or;
(3) If there is more than one “land-grant” institution in the State, and no designation has been made according to paragraph (a)(2) of this section, the institute has been established at the one such institution designated by the Governor of the State to participate in the program, or;
(4) The institute has been designated as an interstate or regional institute by two or more cooperating States as provided in the Act.
(b) The certification of designation made pursuant to paragraph (a) of this section shall originate following the issuance of these regulations, be signed by the highest ranking officer of the college or university at which the institute is established and be submitted to the Director within 90 days of the effective date of these regulations. It shall be accompanied either by the evidence of establishment under the provisions of 30 CFR part 401 or by new evidence of establishment made pursuant to these regulations.
(c) Any institute not previously established under the provisions of the Water Resources Act of 1964 (Pub. L. 88-379, 78 Stat. 331) or the Water Research and Development Act of 1978 (Pub. L. 95-467, 92 Stat. 1305) shall also, in addition to the annual program application specified in § 401.11 of this chapter, submit to the Director the following information:
(1) Evidence of the appointment by the governing authority of the college or university of an officer to receive and account for all funds paid under the provisions of the Act and to make annual reports to the granting agency on work accomplished; and
(2) A management plan for meeting the requirements of the evaluation mandated by § 401.26.
[50 FR 23114, May 31, 1985, as amended at 58 FR 27204, May 7, 1993]
§ 401.7
Programs of institutes.
(a) Release of grant funds to participating institutes is conditioned on the ability of each receiving institute to plan, conduct, or otherwise arrange for:
(1) Competent research, investigations, and experiments of either a basic or practical nature, or both, in relation to water resources;
(2) Promotion of the dissemination and application of the results of these efforts; and
(3) Assistance in the training of scientists in relevant fields of endeavor to water resources through the research, investigations, and experiments.
(b) Such research, investigations, experiments and training may include:
(1) Aspects of the hydrologic cycle;
(2) Supply and demand;
(3) Demineralization of saline and other impaired waters;
(4) Conservation and best use of available supplies of water and methods of increasing such supplies;
(5) Water reuse;
(6) Depletion and degradation of ground-water supplies;
(7) Improvements in the productivity of water when used for agricultural, municipal, and commercial purposes;
(8) The economic, legal, engineering, social, recreational, biological, geographical, ecological, or other aspects of water problems;
(9) Scientific information dissemination activities, including identifying, assembling, and interpreting the results of scientific research on water resources problems, and ;
(10) Providing means for improved communication of research results, having due regard for the varying conditions and needs of the respective States and regions.
(c) An institute shall cooperate closely with other colleges and universities in the State that have demonstrated capabilities for research, information dissemination and graduate training in the development of its program. For purposes of financial management, reporting and other research program management and administration activities, the institutes shall be responsible for performance of the activities of other participating institutions.
(d) Each institute shall cooperate closely with other institutes and other research organizations in the region to increase the effectiveness of the institutes, to coordinate their activities, and to avoid undue duplication of effort.
§§ 401.8-401.10
[Reserved]

Subpart C—Application and Management Procedures
§ 401.11
Applications for grants.
(a) Subject to the availability of appropriated funds, but not to exceed a total of $10 million, an equal amount of dollars will be available to each qualified institute in each fiscal year to assist it in carrying out the purposes of the Act. If the full amount of the appropriated funds is not obligated by the close of the fiscal year for which they were appropriated, the remaining funds shall be made available in the succeeding fiscal year to support competitively selected research projects under the terms of section 104(g) of the Act. Selection and approval of such projects shall be based on criteria to be determined by the Director. Announcement of such criteria shall be made by notice in the Federal Register. The granting agency may retain an amount up to 15 percent of the total appropriation for administrative costs.
(b) The granting agency will annually make available to qualified institutes instructions for the submittal of applications for grants. The instructions will include information pertinent only to a single fiscal year, such as the closing date for applications and the amount of funds initially available to each institute. They also will include notification of the provisions and assurances necessary to ensure that administration of the grant will be conducted in compliance with this chapter and other Federal laws and regulations applicable to grants to institutions of higher learning.
(c) In making its application for funds to which it is entitled under the Act, each institute shall use and follow the standard form for Federal assistance (SF 424, Federal Assistance). No preapplication is required. The institute shall include in section IV of Standard Form 424 evidence that its application was:
(1) Developed in close consultation and collaboration with senior personnel of the State's department of water resources or similar agencies, other leading water resources officials within the State, and interested members of the public;
(2) Coordinated with other institutes in the region for the purposes of avoiding duplication of effort and encouraging regional cooperation in research areas of water management, development, and conservation that have a regional or national character; and
(3) Reviewed for technical merit of its research components by qualified scientists.
(d) Each application shall further include:
(1) A financial plan relating expenditures to scheduled activity and rate of effort to be expended and indicating the times at which there will be need for specified amounts of Federal funds; and
(2) A description of the institute's arrangements for development, administration, and technical oversight of the research program.
(e) Each annual program application is to include separately identifiable proposals for conduct of research to meet the needs of the State and region. Such proposals must set forth for each project:
(1) The nature, scope and objectives of the project to be undertaken;
(2) Its importance to the State, region, or Nation; its relation to other known research projects already completed or in progress; and the anticipated applicability of the research results;
(3) The period during which it will be pursued;
(4) The names and qualifications of the senior professional personnel who will direct and conduct the project;
(5) Its estimated costs, with a breakdown of the costs per year; and
(6) The extent of which it will provide opportunity for the training of scientists.
(f) Each program application shall contain a plan for disseminating information on the results of research and promoting their application. Plans which require the use of grant funds shall contain:
(1) Definition of the topics for dissemination;
(2) Identification of the target audiences for dissemination;
(3) Strategies for accomplishing the dissemination;
(4) Duties and qualifications of the personnel to be involved;
(5) Estimated costs of each identifiable element of the plan; and
(6) Identification of cooperating entities.
(g) The application shall provide assurance that non-Federal dollars will be available to share the costs of the proposed program. The Federal funds are to be matched on a basis of no less than two non-Federal dollars for each Federal dollar, unless this matching requirement has been waived.
(h) The granting agency will evaluate the proposals for consistency with the provisions of its instructions and this chapter and within no more than 90 days request any revisions and additions necessary for such consistency.
[50 FR 23114, May 31, 1985, as amended at 58 FR 27204, May 7, 1993]
§ 401.12
Program management.
(a) Upon approval of each fiscal year's proposed program, the granting agency will transmit to the grantee an award which will incorporate the application and assurances.
(b) The grant is effective and constitutes an obligation of Federal funds in the amount and for the purpose stated in the award document at the time of the Director's signature.
(c)(1) Acceptance of the award document certifies the grantee's assurance that the grant will be administered in compliance with OMB regulations, policies, guidelines, and requirements as described in:
(i) Circular No. A-21, revised, Cost Principles of Educational Institutions;
(ii) Memorandum No. M-92-01, Coordination of Water Resources Information;
(iii) Circular No. A-88, revised, Indirect Cost Rates, Audit and Audit Follow-up at Educational Institutions;
(iv) Circular No. A-110, Uniform Administrative Requirements for Grants and Agreements with Institutions of Higher Education, Hospitals and other Nonprofit Organizations; and
(v) Circular No. A-124, Patents—Small Business Firms and Nonprofit Organizations.
(2) Copies of the documents listed in paragraph (c)(1) of this section shall be available from the granting agency.
[50 FR 23114, May 31, 1985, as amended at 58 FR 27204, May 7, 1993]
§§ 401.13-401.18
[Reserved]

Subpart D—Reporting
§ 401.19
Reporting procedures.
(a) The institutes are encouraged to publish, as technical reports or in the professional literature, the findings, results, and conclusions relating to separately identifiable research projects undertaken pursuant to the Act.
(b) Each institute shall submit to the granting agency, by a date to be specified in the award document, an annual program report which provides:
(1) A statement concerning the relationship of the institute's program to the water problems and issues of the State;
(2) A synopsis of the objectives, methods, and conclusions of each project completed within the period covered;
(3) A progress report on each project continuing into the subsequent fiscal year;
(4) Citations of all reports, papers, publications or other communicable products resulting from each project completed or in progress;
(5) A description of all activities undertaken for the purpose of promoting the application of research results;
(6) A description of cooperative arrangements with other educational institutions, State agencies, and others.
(c) One manuscript of reproducible quality and two copies of the annual program report shall be furnished to the granting agency. One copy of a complete report on the objectives, methods, and conclusions of each research project shall be maintained by the institute and open to inspection.
(d) Appropriate acknowledgment shall be given by institutes to the granting agency's participation in financing activities carried out under provisions of the Act. Such acknowledgment shall be included in all reports, publications, news releases, and other information media developed by institutes and others to publicize, describe, or report upon accomplishments and activities of the program.
(e) An original and two copies of the final “Financial Status Report,” SF 269, shall be furnished to the granting agency within 90 days of completion of the grant period.
§§ 401.20-401.25
[Reserved]

Subpart E—Evaluation
§ 401.26
Evaluation of institutes.
(a) Within 2 years of the date of its certification according to the provisions of § 401.6, each institute will be evaluated for the purpose of determining whether the national interest warrants its continued support under the provisions of the Act. That determination shall be based on:
(1) The quality and relevance of its water resources research as funded under the Act;
(2) Its effectiveness as an institution for planning, conducting, or arranging for research;
(3) Its demonstrated performance in making research results available to users in the State and elsewhere; and
(4) Its demonstrated record in providing for the training of scientists through student involvement in its research program.
(b) An evaluation team, selected by the granting agency on the basis of the members' knowledge of water research and administration, shall evaluate each institute, and may with the concurrence of the granting agency, visit such institutes as it considers necessary. The team is to include at least one individual from each of the following categories:
(1) Employees of the Department of the Interior;
(2) University faculty or other professionals with relevant experience in the conduct of water resources research;
(3) Former directors of water research institutes; and
(4) University faculty or other professionals with relevant experience in information transfer.
(c) The granting agency may request recommendations for team selections from the National Research Council/National Academy of Sciences and from other organizations whose members include the types of individuals cited in paragraph (b) of this section.
(d) The granting agency shall, as an administrative cost, provide the funds for travel and per diem expense of the team members, within the maximum limits allowable under Federal travel regulations (41 CFR subtitle F).
(e) The granting agency has the right to select dates for evaluation visits, and notice of the team's visit shall be provided to the institute being evaluated at least 60 days in advance.
(f) It shall be the responsibility of each institute to provide such documentation of its activities and accomplishments as the granting agency and evaluation team may reasonably request. The request for this documentation shall be made at least 60 days prior to the due date of its receipt.
(g) The team shall, within 90 days after completion of its evaluation, submit a written report of its findings to the granting agency for transmittal to the institute. If an institute is found to have deficiencies in meeting the objectives of the Act, it shall be allowed 1 year to correct them and to report such action to the granting agency. The decision as to the institute's eligibility to receive further funding will rest with the granting agency.
(h) After the initial evaluation, each institute shall be reevaluated at least every 5 years.
[58 FR 27204, May 7, 1993]
Pt. 402

PART 402—WATER-RESOURCES RESEARCH PROGRAM AND THE WATER-RESOURCES TECHNOLOGY DEVELOPMENT PROGRAM

Subpart A—General
Sec.
402.1
Purpose.
402.2
Delegation of authority.
402.3
Definitions.
402.4
Information collection.
402.5
[Reserved]

Subpart B—Description of Water-Resources Programs
402.6
Water-Resources Research Program.
402.7
Water-Resources Technology Development Program.
402.8-402.9
[Reserved]

Subpart C—Application, Evaluation, and Management Procedures
402.10
Research-project applications.
402.11
Technology-development project applications.
402.12
Evaluation of applications for grants and contracts.
402.13
Program management.
402.14
[Reserved]

Subpart D—Reporting
402.15
Reporting procedures.

Authority:
Secs. 105 and 106, Pub. L. 98-242, 98 Stat. 97 (42 U.S.C. 10304 and 10305).

Source:
51 FR 20963, June 10, 1986, unless otherwise noted.

Subpart A—General
§ 402.1
Purpose.
The regulations in this part are issued pursuant to title I of the Water Resources Research Act of 1984 (Pub. L. 98-242, 98 Stat. 97), which authorizes appropriations to, and confers authority upon, the Secretary of the Interior to promote national programs of water-resources research and technology development.
§ 402.2
Delegation of authority.
The Water-Resources Research Program and the Water-Resources Technology Development Program, as authorized by sections 105 and 106 of the Act (42 U.S.C. 10304 and 10305), have been established as components of the USGS. The Secretary of the Interior has delegated to the Director of the USGS authority to take actions and make the determinations that, under the Act, are the responsibility of the Secretary.
§ 402.3
Definitions.
(a) Grant is used in these rules as a generic term for a Federal assistance award, including project grants and cooperative agreements.
(b) Act means the Water Resources Research Act of 1984 (Pub. L. 98-242, 98 Stat. 97).
(c) Educational institution means any educational institution—privately and/or publicly owned.
(d) Dollar-for-dollar matching grant means for each Federal dollar provided to support the projects, a non-Federal dollar also must be provided to the project.
§ 402.4
Information collection.
The information-collection requirements contained in sections 402.10, 402.11, and 402.15 have been approved by the OMB under 44 U.S.C. 3501 et seq. and assigned clearance number 1028-0046. The application proposals being collected will contain technical information that will be used by the USGS as a basis for selection and award of grants. The progress reports being collected will contain a description of all work accomplished and results achieved on each funded project and will enable the USGS to carry out its oversight responsibilities and provide dissemination of technical information.
§ 402.5
[Reserved]

Subpart B—Description of Water-Resources Programs
§ 402.6
Water-Resources Research Program.
(a) Subject to the availability of appropriated funds, the Water-Resources Research Program will provide support, in the form of a dollar-for-dollar matching grant, to educational institutions, private foundations, private firms, individuals, and agencies of local or State governments for research concerning any aspect of a water-resource related problem deemed to be in the national interest. Federal agencies are excluded from receiving matching grants. Grants may be awarded on other than a dollar-for-dollar matching basis in cases where the USGS determines that research on a high-priority subject is of a basic nature that otherwise would not be undertaken.
(b) The types of research to be undertaken under this program are listed below, without indication of priority:
(1) Aspects of the hydrologic cycle;
(2) Supply and demand for water;
(3) Demineralization of saline and other impaired waters;
(4) Conservation and best use of available supplies of water and methods of increasing such supplies;
(5) Water reuse;
(6) Depletion and degradation of groundwater supplies;
(7) Improvements in the productivity of water when used for agricultural, municipal, and commercial purposes; and
(8) The economic, legal, engineering, social, recreational, biological, geographic, ecological, and other aspects of water problems.
(9) Scientific information-dissemination activities, including identifying, assembling, and interpreting the results of scientific and engineering research on water-resources problems.
(10) Providing means for improved communications of research results, having due regard for the varying conditions and needs for the respective States and regions.
§ 402.7
Water-Resources Technology Development Program.
(a) Subject to the availability of appropriated funds, the Water-Resources Technology Development Program will provide funds in the form of grants or contracts to educational institutions, private firms, private foundations, individuals, and agencies of local or State governments for technology development concerning any aspect of water-related technology deemed to be of State, regional, and national importance, including technology associated with improvement of waters of impaired quality and the operation of test facilities. Federal agencies are excluded from receiving grants or contracts. The types of technology-development to be undertaken under this program shall include paragraphs 1 through 10 of § 402.6(b).
(b) The USGS may establish any condition for the matching of funds by the recipient of any grant or cost-sharing under a contract under the technology-development program which the USGS considers to be in the best interest of the Nation.
§§ 402.8-402.9
[Reserved]

Subpart C—Application, Evaluation, and Management Procedures
§ 402.10
Research-project applications.
(a) Only those applications for grants that are in response to and meet the guidelines of specific USGS announcements will be considered for funding appropriated for this program.
(b) The USGS program announcements will identify priorities, matching requirements, particular areas of interest, criteria for evaluation, OMB regulations as appropriate, assurances, closing date, and proposal submittal instructions. Program announcements may also include criteria for high-priority subjects of a basic nature that may be funded on other than a dollar-for-dollar basis. Program announcements will be distributed to names on the current USGS mailing list for the Water-Resources Research Program announcements, including new requests received in response to published notices of upcoming program announcements.
(c) Notification of the availability of the program announcement will be published in the Commerce Business Daily and/or Federal Register.
(d) The application for funds must be signed by an individual or official authorized to commit the applicant and it must contain:
(1) A Standard Form 424 “Federal Assistance,” sections I and II completed by applicant, used as the cover sheet for each proposal.
(2) A project summary of no more than one typed, single-spaced page providing the following specific information:
(i) Identification of the water or water-related problems and the problem-solution approach;
(ii) Identification of the proposed scientific contribution of the problem solution;
(iii) Concise statement of the specific objectives of the project;
(iv) Identification of the approach to be used to accomplish the work; and
(v) Identification of potential users of the proposed work.
(3) Narrative information, as specified in the published program announcement, such as project title, project objectives, background information, research tasks, methodology to conduct the research task, the relevancy of the proposed project to water-resources problems, qualifications of the principal investigators and their organizations, and proposed budget with supporting information sufficient to allow evaluation of costs.
§ 402.11
Technology-development project applications.
(a) Grant awards will be used to support those portions of the program for which the principal purpose is other than as described in § 402.11(b). Program announcements and applications will be governed by the same procedures provided in § 402.10.
(b) If it is determined that the principal purpose of a planned award (or awards) is to acquire goods or services for the direct benefit or use of the Government, the action must be regarded as a procurement contract. A competitive solicitation prepared in accordance with applicable acquisition regulations will be issued to interested parties. Notification of the availability of any contract solicitation will be published in the Commerce Business Daily, unless waived in accordance with § 5.202 of the Federal Acquisition Regulation (FAR). Contracts may be awarded without full and open competition only if justified in accordance with FAR subpart 6.3.
§ 402.12
Evaluation of applications for grants and contracts.
(a) Grants. (1) Each grant application will receive technical evaluations from Government and/or non-Government scientific or engineering personnel. Utilizing the criteria for evaluation identified in the applicable announcement, each reviewer will assign a technical score.
(2) Grant applications with low technical ratings will be screened out, and the remaining grant applications will be rank-ordered by review panels.
(3) USGS program officials will compile a single, consolidated rank-ordered list of the grant applications based on technical scoring, program needs and published priorities, and the available Federal funds.
(b) Contracts. Proposals for contract awards will be evaluated by a USGS panel. Contracts will be awarded according to procedures contained in the FAR, the Department of the Interior Acquisition Regulation, and in acquisition policy releases issued by the Department and by the USGS.
§ 402.13
Program management.
(a) After the conclusion of negotiations, the USGS will transmit a grant or contract-award document, as appropriate, setting forth the terms of the award.
(b) Grants. Recipients will be required to execute funded projects in accordance with OMB Circulars governing cost principles, administrative requirements, and audit, as applicable to their organization type. In addition, OMB Circular A-67, Coordination of Federal Activities in the Acquisition of Certain Water Data, is applicable to awards under these programs.
(c) Contracts. Administrative requirements for performance of research contracts will be established in the contract clauses in conformance with applicable procurement regulations and other interior or USGS acquisition policy documents. OMB Circular A-67 will also apply to some contract awards under this program.
§ 402.14
[Reserved]

Subpart D—Reporting
§ 402.15
Reporting procedures.
(a) Grantees or contractors will be required to submit the following technical reports to the USGS address identified under the terms and conditions of each award.
(1) Quarterly Technical Progress Report. This report shall include a description of all work accomplished, results achieved, and any changes that affect the project's scope of work, time schedule, and personnel assignments.
(2) Draft Technical Completion Report. The draft report will be required for review prior to submission of the final technical completion report.
(3) Final Technical Completion Report. The final report and a camera-ready copy shall be submitted to the USGS within 90 days after the expiration date of the award and shall include a summary of all work accomplished, results achieved, conclusions, and recommendations. The camera-ready copy shall be prepared in a manner suitable for reproduction by a photographic process. Format will be specified in the terms and conditions of the award.
(4) Final Report Abstract. A complete Water-Resources Scientific Information Center Abstract Form 102 and National Technical Information Service Form 79 shall be submitted with the final report.
(b) Grantees or contractors will be required to submit financial, administrative, and closeout reports as identified under the terms of each award. Reporting requirements will conform to the procedures described in the Departmental Manual of the Department of the Interior at 505 DM 1-5.
(c) Contracts for technology-development projects may also require delivery of hardware items produced and/or specifications, drawings, test results, or other data describing the funded technology.

FINDING AIDS
A list of CFR titles, subtitles, chapters, subchapters and parts and an alphabetical list of agencies publishing in the CFR are included in the CFR Index and Finding Aids volume to the Code of Federal Regulations which is published separately and revised annually.
Material Approved for Incorporation by Reference
Table of CFR Titles and Chapters
Alphabetical List of Agencies Appearing in the CFR
List of CFR Sections Affected
Title 30—Mineral Resources
Material Approved for Incorporation by Reference

Material Approved for Incorporation by Reference
(Revised as of July 1, 2008)
The Director of the Federal Register has approved under 5 U.S.C. 552(a) and 1 CFR Part 51 the incorporation by reference of the following publications. This list contains only those incorporations by reference effective as of the revision date of this volume. Incorporations by reference found within a regulation are effective upon the effective date of that regulation. For more information on incorporation by reference, see the preliminary pages of this volume.
30 CFR (PARTS 200 to 699)
MINERALS MANAGEMENT SERVICE, DEPARTMENT OF THE INTERIOR
30 CFR
American Concrete Institute
P.O. Box 9094, Farmington Hill, Michigan 48333-9094
ACI Standard 318-95, Building Code Requirements for Reinforced Concrete, plus Commentary on Building Code Requirements for Reinforced Concrete (ACI 318R-95)
250.198; 250.901
ACI Standard 357-R-84 (Reapproved 1997), Guide for the Design and Construction of Fixed Offshore Concrete Structures
250.198; 250.901
American Institute of Steel Construction, Inc.
One East Wacker Drive, Suite 700, Chicago, Illinois 60601-1802
AISC 360-05: Standard Specification for Structural Steel Buildings, 2005
250.198; 250.901
American Society of Mechanical Engineers (ASME)
Three Park Avenue, New York, NY 10016-5990; Order inquiries: 22 Law Drive, P.O. Box 2900, Fairfield, New Jersey 07007; Telephone: 1-800-843-2763
ANSI/ASME Boiler and Pressure Vessel Code, Section I, Rules for Construction of Power Boilers, 2004 including July 1, 2005 Addenda
250.198; 250.803(b)(1), (b)(1)(i); 250.1629(b)(1), (b)(1)(i)
ANSI/ASME Boiler and Pressure Vessel Code, Section IV: Rules for Construction of Heating Boilers, including Appendices 1, 2, 3, 5, and 6 and non-Mandatory Appendices B, C, D, E, F, H, I, K, L and M, and the Guide to Manufacturers Data Report Forms, 2004 Edition, including July 1, 2005 Addenda
250.198; 250.803(b)(1), (b)(1)(i); 250.1629(b)(1); 250.1629(b)(1)(i)
ANSI/ASME Boiler and Pressure Vessel Code, Section VIII, Division 1: Rules for Construction of Pressure Vessels, 2004, including July 2005 Addenda
250.198; 250.803(b)(1), (b)(1)(i); 250.1629(b)(1), (b)(1)(i)
ANSI/ASME Boiler and Pressure Vessel Code, Section VIII, Division 2: Alternative Rules, 2004, including 2005 Addenda
250.198; 250.803(b)(1)and (b)(1)(i); 250.1629(b)(1)and (b)(1)(i)
ANSI/ASME B 16.5-2003, Pipe Flanges and Flanged Fittings
250.198; 250.1002(b)(2)
ANSI/ASME B 31.8-2003, Gas Transmission and Distribution Piping Systems
250.198; 250.1002(a)
ANSI/ASME SPPE-1-1994 and SPPE-1d-1996 Addenda, Quality Assurance and Certification of Safety and Pollution Prevention Equipment Used in Offshore Oil and Gas Operations
250.198; 250.806(a)(2)(i)
ANSI Z88.2-1992, American National Standard for Respiratory Protection
250.198; 250.490
The American Petroleum Institute
1220 L Street, NW., Washington, DC 20005-4070; Telephone: (202) 682-8000
API 510, Pressure Vessel Inspection Code: In-Service Inspection, Rating, Repair and Alteration (Downstream Segment) Ninth edition, June 2006
250.198; 250.803; 250.1629
API Bulletin 2INT-DG, Interim Guidance for Design of Offshore Structures for Hurrican Conditions, Product No. G2DGINT, May 2007
250.195; 250.901
API Bulletin 2INT-EX, Interim Guidance for Assessment of Existing Offshore Structures for Hurrican Conditions, May 2007
250.195; 250.901
API Bulletin 2INT-MET, Interim Guidance on Hurricane Condidions in the Gulf of Mexico, Product No. G2INTMET, May 2007
250.195; 250.901
API RP 2A-WSD, Recommended Practice for Planning, Designing, and Constructing Fixed Offshore Platforms—Working Stress Design, Twenty-first Edition, December 2000, Errata and Supplements 1 (December 2002) and 2, (October 2005), API Stock No. G2AWSD
250.198; 250.901(a)(4); 250.908(a); 250.920
API RP 2D, Recommended Practice for Operation and Maintenance of Offshore Cranes, Fifth Edition, June 2003
250.108(a)(1); 250.198
API RP 2FPS, Recommended Practice for Planning, Designing, and Constructing Floating Production Systems, First edition, March 2001
250.198; 250.901
API RP 2RD, Recommended Practice for Design of Risers for Floating Production Systems (FPSs) and Tension Leg Platforms, First edition, June 1998, reaffirmed May 2006
250.198; 250.800; 250.901; 250.1002
API RP 2SK, Recommended Practice for Design and Analysis of Stationkeeping Systems for Floating Structures, Third edition, October 2005
250.198; 250.800; 250.901
API RP 2SM, Recommended Practice for Design, Manufacture, Installation, and Maintenance of Synthetic Fiber Ropes for Offshore Mooring, First edition, March 2001
250.198; 250.901
API RP 2T, Recommended Practice for Planning, Designing, and Constructing Tension Leg Platforms, Second edition, August 1997
250.198; 250.901
API RP 14B Recommended Practice for Design, Installation, Repair, and Operation of Subsurface Safety Valve Systems, Fifth Edition, October 2005, also available as ISO 10417: 2004 (Identical) Petroleum and Natural Gas Industries—Subsurface Safety Valve Systems—Design, Installation, Operation and Redress
250.198; 250.801(e)(4); 250.804(a)(1)(i)
API RP 14C Recommended Practice for Analysis, Design, Installation, and Testing of Basic Surface Safety Systems for Offshore Production Platforms, Seventh Edition, March 2001
250.125; 250.198; 250.292; 250.802(b), (e)(2); 250.803(a), (b)(2)(i), (b)(4), (b)(5)(i), (b)(7), (b)(9)(v), (c)(2); 250.804(a), (a)(5); 250.1002(d); 250.1004(b)(9); 250.1628(c), (d)(2); 250.1629(b)(2), (b)(4)(v); 250.1630(a)
API RP 14E, Recommended Practice for Design and Installation of Offshore Production Platform Piping Systems, Fifth Edition, October 1, 1991, reaffirmed June 2000
250.198; 250.802(e)(3); 250.1628(b)(2), (d)(3)
API RP 14F, Recommended Practice for Design and Installation of Electrical Systems for Fixed and Floating Offshore Petroleum Facilities for Unclassified and Class 1, Division 1 and Division 2 Locations, Fourth Edition, June 1999, API Stock No. G14F04
250.114(c); 250.198; 250.803(b)(9)(v); 250.1629(b)(4)(v)
API RP 14FZ, Recommended Practice for Design and Installation of Electrical Systems for Fixed and Floating Offshore Petroleum Facilities for Unclassified and Class 1, Zone 0, Zone 1 and Zone 2 Locations, First Edition, September 2001, API Stock No. G14FZ1
250.114(c); 250.198; 250.803(b)(9)(v); 250.1629(b)(4)(v)
API RP 14G, Recommended Practice for Fire Prevention and Control on Open Type Offshore Production Platforms, Third Edition, December 1, 1993 (Reaffirmed June 2000)
250.198; 250.803(b)(8), (b)(9)(v); 250.1629(b)(3), (b)(4)(v)
API RP 14H, Recommended Practice for the Installation, Maintenance and Repair of Surface Safety Valves and Underwater Safety Valves Offshore, Fourth Edition, July 1, 1994, API Stock No. G14H04
250.198; 250.802(d); 250.804(a)(4)
API RP 14J, Recommended Practice for Design and Hazards Analysis for Offshore Production Facilities, Second edition, May 2001, API Order No. G14J02
250.198; 250.800; 250.901
API RP 53, Recommended Practice for Blowout Prevention Equipment Systems for Drilling Wells, Third Edition, reaffirmed September 2004
250.198; 250.442; 250.446
API RP 65, Recommended Practice for Cementing Shallow Water Flow Zones in Deep Water Wells, FirstEdition, September 2002
250.198; 250.415
API RP 500, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class 1, Division 1 and Division 2, Second Edition, November 1997 (Reaffirmed November 2002)
250.114(a); 250.198; 250.459; 250.802(e)(4)(i); 250.803(b)(9)(i); 250.1628(b)(3); 250.1628(d)(4)(i); 250.1629(b)(4)(i)
API RP 505, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class 1, Zone 0, Zone 1, and Zone 2, First Edition, November 1997 (Reaffirmed November 2002)
250.114(a); 250.459; 250.802(e)(4)(i); 250.803(b)(9)(i); 250.1628(b)(3); 250.1628(d)(4)(i); 250.1629(b)(4)(i)
API Specification 2C, Specification for Offshore Pedestal Mounted Cranes, Sixth Edition, Effective date: September 2004
250.108; 250.198
API Spec 6A, Specification for Wellhead and Christmas Tree Equipment (also issued as ISO 10423:2003), Nineteenth Edition, Effective Date: February 1, 2005
250.198; 250.806(a)(3); 250.1002
API Spec 6A V1, Specification for Verification Test of Wellhead Surface Safety Valves and Underwater Safety Valves for Offshore Service, First Edition, February 1, 1996 (Reaffirmed January 2003), API Stock No. G06AV1
250.198; 250.806(a)(3)
API Specification 6D: Specification for Pipeline Valves, Twenty-second edition, January 2002 (also available as ISO 14313:1999), MOD, Petroleum and Natural Gas Industries—Pipeline Transportation Systems—Pipeline Valves, Effective Date: July 1, 2002; Proposed National Adoption, includes Annex F, March 1, 2005
250.198; 250.1002(b)(1)
API Specification 14A, Specification for Subsurface Safety Valve Equipment, Tenth Edition, November 2000; also available as ISO 10432:1999, Petroleum and Natural Gas Industries—Downhole Equipment—Subsurface Safety Valve Equipment, Effective date: May 15, 2001
250.198; 250.806(a)(3)
API Specification 17J, Specification for Unbonded Flexible Pipe, Second edition dated November 1999, including Errata dated May 25, 2001 and Addendum 1 dated June 2003, effective date December 2002
250.198; 250.803; 250.1002; 250.1007
API Specification Q1, Specification for Quality Programs for the Petroleum, Petrochemical and Natural Gas Industry dated June 15, 2003, including August 2003 errata, Seventh edition, also available as ISO/TS 29001, Effective Date: December 15, 2003
250.198; 250.806(a)(2)(ii)
API Standard 2551, Standard Method for Measurement and Calibration of Horizontal Tanks, First Edition, 1965, reaffirmed March 2002
250.198; 250.1202(l)(4)
API Standard 2552, Measurement and Calibration of Spheres and Spheroids, First Edition, 1966, reaffirmed February 2006
250.198; 250.1202(l)(4)
API Standard 2555, Method for Liquid Calibration of Tanks, First Edition, September 1966, reaffirmed March 2002
250.198; 250.1202(l)(4)
API RP 2556, Recommended Practice for Correcting Gauge Tables for Incrustation, Second Edition, August 1993 (Reaffirmed November 2003), API Stock No. H25560
250.198; 250.1202(l)(4)
API MPMS, Chapter 1, Vocabulary, Second Edition, July 1994, API Stock No., H01002
250.198; 250.1201
API MPMS, Chapter 2, Tank Calibration, Section 2A: Measurement and Calibration of Upright Cylindrical Tanks by the Manual Tank Strapping Method, First Edition, reaffirmed March 2002
250.198; 250.1202(1)(4)
API MPMS, Chapter 2, Section 2B, Calibration of Upright Cylindrical Tanks Using the Optical Reference Line Method, First Edition, March 1989, reaffirmed March 2002
250.198; 250.1202(1)(4)
API MPMS, Chapter 3, Tank Gauging, Section 1A, Standard Practice for the Manual Gauging of Petroleum and Petroleum Products, Second Edition, August 2005
250.198; 250.1202(1)(4)
API MPMS, Chapter 3, Section 1B, Standard Practice for Level Measurement of Liquid Hydrocarbons in Stationary Tanks by Automatic Tank Gauging, Second Edition, June 2001
250.198; 250.1202(1)(4)
API MPMS, Chapter 4, Proving Systems, Section 1: Introduction, Third Edition, February 2005
250.198; 250.1202(a)(3), (f)(1)
API MPMS, Chapter 4, Section 2: Displacement Provers, Third Edition, September 2003
250.198; 250.1202(a)(3), (f)(1)
API MPMS, Chapter 4, Section 4, Tank Provers, Second Edition, May 1998
250.198; 250.1202(a)(3), (f)(1)
API MPMS, Chapter 4, Section 5, Master-Meter Provers, Second Edition, May 2000
250.198; 250.1202(a)(3), (f)(1)
API MPMS, Chapter 4, Section 6, Proving Systems: Pulse Interpolation, Second Edition, 1999, reaffirmed 2003
250.198; 250.1202(a)(3) and (f)(1)
API MPMS, Chapter 4, Section 7, Proving Systems: Field Standard Test Measures, Second Edition, December 1998 reaffirmed 2003
250.198; 250.1202(a)(3), (f)(1)
API MPMS, Chapter 5: Metering, Section 1, General Considerations for Measurement by Meters, Measurement Coordination Department, Fourth Edition, September 2005
250.198; 250.1202(a)(3)
API MPMS, Chapter 5, Section 2, Measurement of Liquid Hydrocarbons by Displacement Meters, Third Edition, September 2005
250.198; 250.1202(a)(3)
API MPMS, Chapter 5, Section 3, Measurement of Liquid Hydrocarbons by Turbine Meters, Fifth Edition, September 2005,
250.198; 250.1202(a)(3)
API MPMS, Chapter 5, Section 4, Accessory Equipment for Liquid Meters, Fourth Edition, September 2005
250.198; 250.1202(a)(3)
API MPMS, Chapter 5, Section 5, Fidelity and Security of Flow Measurement Pulsed-Data Transmission Systems, Second Edition, August 2005
250.198; 250.1202(a)(3)
API MPMS, Chapter 6, Metering Assemblies, Section 1, Lease Automatic Custody Transfer (LACT) Systems, Second Edition, May 1991, reaffirmed March 2002
250.198; 250.1202(a)(3)
API MPMS, Chapter 6, Section 6, Pipeline Metering Systems, Second Edition, May 1991, reaffirmed March 2002
250.198; 250.1202(a)(3)
API MPMS, Chapter 6, Section 7, Metering Viscous Hydrocarbons, Second Edition, May 1991, reaffirmed March 2002
250.198; 250.1202(a)(3)
API MPMS, Chapter 7, Temperature Determination—Measurement Coordination, First edition, June 2001
250.198; 250.1202(a)(3), (l)(4)
API MPMS, Chapter 8, Sampling, Section 1, Standard Practice for Manual Sampling of Petroleum and Petroleum Products, Third Edition, October 1995, reaffirmed March 2006
250.198; 250.1202(b)(4)(i), (l)(4)
API MPMS, Chapter 8, Section 2, Standard Practice for Automatic Sampling of Liquid Petroleum and Petroleum Products, Second Edition, October 1995, reaffirmed June 2005
250.198; 250.1202(a)(3), (l)(4)
API MPMS, Chapter 9, Density Determination, Section 1, Standard Test Method for Density, Relative Density (Specific Gravity), or API Gravity of Crude Petroleum and Liquid Petroleum Products by Hydrometer Method, Second edition, reaffirmed October 2005
250.198; 250.1202(a)(3); 250.1202(l)(4)
API MPMS Chapter 9, Section 2—Standard Test Method for Density or Relative Density of Light Hydrocarbons by Pressure Hydrometer, Second edition, March 2003
250.198; 250.1202(a)(3); 250.1202(l)(4)
API MPMS, Chapter 10, Sediment and Water, Section 1, Standard Test Method for Sediment in Crude Oils and Fuel Oils by the Extraction Method, Second Edition, October 2002
250.198; 250.1202(a)(3), (l)(4)
API MPMS, Chapter 10, Section 2, Determination of Water in Crude Oil by Distillation Method, First Edition, April 1981, reaffirmed 2005
250.198; 250.1202(a)(3), (l)(4)
API MPMS, Chapter 10, Section 3, Standard Test Method for Water and Sediment in Crude Oil by the Centrifuge Method (Laboratory Procedure), Second Edition, May 2003
250.198; 250.1202(a)(3), (l)(4)
API MPMS, Chapter 10, Section 4, Determination of Water and/or Sediment in Crude Oil by the Centrifuge Method (Field Procedure), Third Edition, December 1999
250.198; 250.1202(a)(3), (l)(4)
API MPMS, Chapter 10, Sediment and Water, Section 9, Standard Test Method for Water in Crude Oils by Coulometric Karl Fischer Titration, Second Edition, reaffirmed 2005
250.198; 250.1202(a)(3), (l)(4)
API MPMS, Chapter 11, Physical Properties Data, Addendum to Section 2, Part 2, Compressibility Factors for Hydrocarbons, Correlation of Vapor Pressure for Commercial Natural Gas Liquids, First Edition, reaffirmed December 2002
250.198; 250.1202(a)(3)
API MPMS, Chapter 11.1, Volume Correction Factors, Volume I, Table 5A—Generalized Crude Oils and JP-4 Correction of Observed API Gravity to API Gravity at 60° F, and Table 6A—Generalized Crude Oils and JP-4 Correction of Volume to 60° F Against API Gravity at 60° F, API Standard 2540, First Edition, August 1980, reaffirmed March 1997; API Stock No. H27000
250.198; 250.1202(a)(3), (g)(3), (l)(4)
API MPMS, Chapter 11.2.2, Compressibility Factors for Hydrocarbons: 0.350-0.637 Relative Density (60° F/60° F) and -50° F to 140° F Metering Temperature, Second Edition, October 1986, reaffirmed December 2002
250.198; 250.1202(a)(3), (g)(4)
API MPMS, Chapter 12, Calculation of Petroleum Quantities, Section 2, Calculation of Petroleum Quantities Using Dynamic Measurement Methods and Volumetric Correction Factors, Part 1: Introduction, Second Edition, May 1995 (Reaffirmed March 2002)
250.198; 250.1202
API MPMS, Chapter 12, Calculation of Petroleum Quantities, Section 2, Calculation of Petroleum Quantities Using Dynamic Measurement Methods and Volumetric Correction Factors, Part 2: Measurement Tickets, Third Edition, June 2003
250.198; 250.1202
API MPMS, Chapter 14, Natural Gas Fluids Measurement, Section 3, Concentric Square-Edged Orifice Meters, Part 1: General Equations and Uncertainty Guidelines, Third Edition, reaffirmed January 2003
250.198; 250.1203(b)(2)
API MPMS, Chapter 14, Section 3, Part 2, Specification and Installation Requirements, Fourth Edition, reaffirmed March 2006
250.198; 250.1203(b)(2)
API Chapter 14---Natural Gas Fluids Measurement, Section 3—Concentric, Square-Edged Orifice Meters, Part 3—Natural Gas Applications, Third Edition, reaffirmed January 2003
250.198; 250.1203(b)(2)
API MPMS, Chapter 14.5, Calculation of Gross Heating Value, Relative Density, and Compressibility Factor for Natural Gas Mixtures from Compositional Analysis, Second Edition, reaffirmed March 2002
250.198; 250.1203(b)(2)
API MPMS, Chapter 14, Section 6, Continuous Density Measurement, Second Edition, April 1991, reaffirmed 2006
250.198; 250.1203(b)(2)
API MPMS, Chapter 14, Section 8, Liquefied Petroleum Gas Measurement, Second Edition, July 1997; reaffirmed March 2002
250.198; 250.1203(b)(2)
API MPMS, Chapter 20, Section 1, Allocation Measurement, First Edition, reaffirmed October 2006
250.198; 250.1202(k)(1)
API MPMS, Chapter 21, Flow Measurement Using Electronic Metering Systems, Section 1 - Electronic Gas Measurement, First Edition, reaffirmed July 2005
250.198; 250.1203(b)(4)
The American Society for Testing and Materials
100 Barr Harbor Drive, West Conshohocken, PA 19428-2959; Telephone: (610) 832-9585, FAX: (610) 832-9555
ASTM Standard C 33-99a, Standard Specification for Concrete Aggregates
250.198; 250.901(a)
ASTM Standard C94/C94M-99, Standard Specification for Ready-Mixed Concrete
250.198; 250.901(a)
ASTM Standard C 150-99, Standard Specification for Portland Cement
250.198; 250.901(a)
ASTM Standard C 330-99, Standard Specification for Lightweight Aggregates for Structural Concrete
250.198; 250.901(a)
ASTM Standard C 595-98, Standard Specification for Blended Hydraulic Cements
250.198; 250.901(a)
The American Welding Society
550 NW LeJeune Road, P.O. Box 351040, Miami, Florida 33135
AWS D1.1-2000, Structural Welding Code—Steel, 2000
250.198; 250.901(a)
AWS D1.4-98, Structural Welding Code—Reinforcing Steel, 1998
250.198; 250.901(a)
ANSI/AWS D3.6M, Specification for Underwater Welding, 1999
250.198; 250.901(a)
The National Association of Corrosion Engineers
First Services Department, 1440 South Creek Drive, Houston, Texas 77218
NACE Standard MR0175-2003, Standard Material Requirements: Metals for Sulfide Stress Cracking and Stress Corrosion Cracking Resistance in Sour Oilfield Environments, 2003
250.198; 250.901(a)
NACE Standard RP 01-76-2003, Standard Recommended Practice, Corrosion Control of Steel Fixed Offshore Structures Associated with Petroleum Production
250.198; 250.901(a)
Chap.

Table of CFR Titles and Chapters
(Revised as of July 1, 2008)

Title 1—General Provisions
I
Administrative Committee of the Federal Register (Parts 1—49)
II
Office of the Federal Register (Parts 50—299)
IV
Miscellaneous Agencies (Parts 400—500)

Title 2—Grants and Agreements
Subtitle A—Office of Management and Budget Guidance for Grants and Agreements
I
Office of Management and Budget Governmentwide Guidance for Grants and Agreements (Parts 100—199)
II
Office of Management and Budget Circulars and Guidance (200—299)
Subtitle B—Federal Agency Regulations for Grants and Agreements
III
Department of Health and Human Services (Parts 300— 399)
VI
Department of State (Parts 600—699)
VIII
Department of Veterans Affairs (Parts 800—899)
IX
Department of Energy (Parts 900—999)
XI
Department of Defense (Parts 1100—1199)
XII
Department of Transportation (Parts 1200—1299)
XIV
Department of the Interior (Parts 1400—1499)
XV
Environmental Protection Agency (Parts 1500—1599)
XVIII
National Aeronautics and Space Administration (Parts 1880—1899)
XXII
Corporation for National and Community Service (Parts 2200—2299)
XXIII
Social Security Administration (Parts 2300—2399)
XXIV
Housing and Urban Development (Parts 2400—2499)
XXV
National Science Foundation (Parts 2500—2599)
XXVI
National Archives and Records Administration (Parts 2600—2699)
XXVII
Small Business Administration (Parts 2700—2799)
XXVIII
Department of Justice (Parts 2800—2899)
XXXII
National Endowment for the Arts (Parts 3200—3299)
XXXIII
National Endowment for the Humanities (Parts 3300—3399)
XXXV
Export-Import Bank of the United States (Parts 3500—3599)
XXXVII
Peace Corps (Parts 3700—3799)

Title 3—The President
I
Executive Office of the President (Parts 100—199)

Title 4—Accounts
I
Government Accountability Office (Parts 1—99)

Title 5—Administrative Personnel
I
Office of Personnel Management (Parts 1—1199)
II
Merit Systems Protection Board (Parts 1200—1299)
III
Office of Management and Budget (Parts 1300—1399)
V
The International Organizations Employees Loyalty Board (Parts 1500—1599)
VI
Federal Retirement Thrift Investment Board (Parts 1600—1699)
VIII
Office of Special Counsel (Parts 1800—1899)
IX
Appalachian Regional Commission (Parts 1900—1999)
XI
Armed Forces Retirement Home (Parts 2100—2199)
XIV
Federal Labor Relations Authority, General Counsel of the Federal Labor Relations Authority and Federal Service Impasses Panel (Parts 2400—2499)
XV
Office of Administration, Executive Office of the President (Parts 2500—2599)
XVI
Office of Government Ethics (Parts 2600—2699)
XXI
Department of the Treasury (Parts 3100—3199)
XXII
Federal Deposit Insurance Corporation (Parts 3200—3299)
XXIII
Department of Energy (Parts 3300—3399)
XXIV
Federal Energy Regulatory Commission (Parts 3400—3499)
XXV
Department of the Interior (Parts 3500—3599)
XXVI
Department of Defense (Parts 3600— 3699)
XXVIII
Department of Justice (Parts 3800—3899)
XXIX
Federal Communications Commission (Parts 3900—3999)
XXX
Farm Credit System Insurance Corporation (Parts 4000—4099)
XXXI
Farm Credit Administration (Parts 4100—4199)
XXXIII
Overseas Private Investment Corporation (Parts 4300—4399)
XXXV
Office of Personnel Management (Parts 4500—4599)
XL
Interstate Commerce Commission (Parts 5000—5099)
XLI
Commodity Futures Trading Commission (Parts 5100—5199)
XLII
Department of Labor (Parts 5200—5299)
XLIII
National Science Foundation (Parts 5300—5399)
XLV
Department of Health and Human Services (Parts 5500—5599)
XLVI
Postal Rate Commission (Parts 5600—5699)
XLVII
Federal Trade Commission (Parts 5700—5799)
XLVIII
Nuclear Regulatory Commission (Parts 5800—5899)
L
Department of Transportation (Parts 6000—6099)
LII
Export-Import Bank of the United States (Parts 6200—6299)
LIII
Department of Education (Parts 6300—6399)
LIV
Environmental Protection Agency (Parts 6400—6499)
LV
National Endowment for the Arts (Parts 6500—6599)
LVI
National Endowment for the Humanities (Parts 6600—6699)
LVII
General Services Administration (Parts 6700—6799)
LVIII
Board of Governors of the Federal Reserve System (Parts 6800—6899)
LIX
National Aeronautics and Space Administration (Parts 6900—6999)
LX
United States Postal Service (Parts 7000—7099)
LXI
National Labor Relations Board (Parts 7100—7199)
LXII
Equal Employment Opportunity Commission (Parts 7200—7299)
LXIII
Inter-American Foundation (Parts 7300—7399)
LXIV
Merit Systems Protection Board (Parts 7400—7499)
LXV
Department of Housing and Urban Development (Parts 7500—7599)
LXVI
National Archives and Records Administration (Parts 7600—7699)
LXVII
Institute of Museum and Library Services (Parts 7700—7799)
LXVIII
Commission on Civil Rights (Parts 7800—7899)
LXIX
Tennessee Valley Authority (Parts 7900—7999)
LXXI
Consumer Product Safety Commission (Parts 8100—8199)
LXXIII
Department of Agriculture (Parts 8300—8399)
LXXIV
Federal Mine Safety and Health Review Commission (Parts 8400—8499)
LXXVI
Federal Retirement Thrift Investment Board (Parts 8600—8699)
LXXVII
Office of Management and Budget (Parts 8700—8799)
XCVII
Department of Homeland Security Human Resources Management System (Department of Homeland Security—Office of Personnel Management) (Parts 9700—9799)
XCIX
Department of Defense Human Resources Management and Labor Relations Systems (Department of Defense—Office of Personnel Management) (Parts 9900—9999)

Title 6—Domestic Security
I
Department of Homeland Security, Office of the Secretary (Parts 0—99)
X
Privacy and Civil Liberties Oversight Board (Parts 1000—1099)

Title 7—Agriculture
Subtitle A—Office of the Secretary of Agriculture (Parts 0—26)
Subtitle B—Regulations of the Department of Agriculture
I
Agricultural Marketing Service (Standards, Inspections, Marketing Practices), Department of Agriculture (Parts 27—209)
II
Food and Nutrition Service, Department of Agriculture (Parts 210—299)
III
Animal and Plant Health Inspection Service, Department of Agriculture (Parts 300—399)
IV
Federal Crop Insurance Corporation, Department of Agriculture (Parts 400—499)
V
Agricultural Research Service, Department of Agriculture (Parts 500—599)
VI
Natural Resources Conservation Service, Department of Agriculture (Parts 600—699)
VII
Farm Service Agency, Department of Agriculture (Parts 700—799)
VIII
Grain Inspection, Packers and Stockyards Administration (Federal Grain Inspection Service), Department of Agriculture (Parts 800—899)
IX
Agricultural Marketing Service (Marketing Agreements and Orders; Fruits, Vegetables, Nuts), Department of Agriculture (Parts 900—999)
X
Agricultural Marketing Service (Marketing Agreements and Orders; Milk), Department of Agriculture (Parts 1000—1199)
XI
Agricultural Marketing Service (Marketing Agreements and Orders; Miscellaneous Commodities), Department of Agriculture (Parts 1200—1299)
XIV
Commodity Credit Corporation, Department of Agriculture (Parts 1400—1499)
XV
Foreign Agricultural Service, Department of Agriculture (Parts 1500—1599)
XVI
Rural Telephone Bank, Department of Agriculture (Parts 1600—1699)
XVII
Rural Utilities Service, Department of Agriculture (Parts 1700—1799)
XVIII
Rural Housing Service, Rural Business-Cooperative Service, Rural Utilities Service, and Farm Service Agency, Department of Agriculture (Parts 1800—2099)
XX
Local Television Loan Guarantee Board (Parts 2200—2299)
XXVI
Office of Inspector General, Department of Agriculture (Parts 2600—2699)
XXVII
Office of Information Resources Management, Department of Agriculture (Parts 2700—2799)
XXVIII
Office of Operations, Department of Agriculture (Parts 2800—2899)
XXIX
Office of Energy Policy and New Uses, Department of Agriculture (Parts 2900—2999)
XXX
Office of the Chief Financial Officer, Department of Agriculture (Parts 3000—3099)
XXXI
Office of Environmental Quality, Department of Agriculture (Parts 3100—3199)
XXXII
Office of Procurement and Property Management, Department of Agriculture (Parts 3200—3299)
XXXIII
Office of Transportation, Department of Agriculture (Parts 3300—3399)
XXXIV
Cooperative State Research, Education, and Extension Service, Department of Agriculture (Parts 3400—3499)
XXXV
Rural Housing Service, Department of Agriculture (Parts 3500—3599)
XXXVI
National Agricultural Statistics Service, Department of Agriculture (Parts 3600—3699)
XXXVII
Economic Research Service, Department of Agriculture (Parts 3700—3799)
XXXVIII
World Agricultural Outlook Board, Department of Agriculture (Parts 3800—3899)
XLI
[Reserved]
XLII
Rural Business-Cooperative Service and Rural Utilities Service, Department of Agriculture (Parts 4200—4299)

Title 8—Aliens and Nationality
I
Department of Homeland Security (Immigration and Naturalization) (Parts 1—499)
V
Executive Office for Immigration Review, Department of Justice (Parts 1000—1399)

Title 9—Animals and Animal Products
I
Animal and Plant Health Inspection Service, Department of Agriculture (Parts 1—199)
II
Grain Inspection, Packers and Stockyards Administration (Packers and Stockyards Programs), Department of Agriculture (Parts 200—299)
III
Food Safety and Inspection Service, Department of Agriculture (Parts 300—599)

Title 10—Energy
I
Nuclear Regulatory Commission (Parts 0—199)
II
Department of Energy (Parts 200—699)
III
Department of Energy (Parts 700—999)
X
Department of Energy (General Provisions) (Parts 1000—1099)
XIII
Nuclear Waste Technical Review Board (Parts 1303—1399)
XVII
Defense Nuclear Facilities Safety Board (Parts 1700—1799)
XVIII
Northeast Interstate Low-Level Radioactive Waste Commission (Parts 1800—1899)

Title 11—Federal Elections
I
Federal Election Commission (Parts 1—9099)

Title 12—Banks and Banking
I
Comptroller of the Currency, Department of the Treasury (Parts 1—199)
II
Federal Reserve System (Parts 200—299)
III
Federal Deposit Insurance Corporation (Parts 300—399)
IV
Export-Import Bank of the United States (Parts 400—499)
V
Office of Thrift Supervision, Department of the Treasury (Parts 500—599)
VI
Farm Credit Administration (Parts 600—699)
VII
National Credit Union Administration (Parts 700—799)
VIII
Federal Financing Bank (Parts 800—899)
IX
Federal Housing Finance Board (Parts 900—999)
XI
Federal Financial Institutions Examination Council (Parts 1100—1199)
XIV
Farm Credit System Insurance Corporation (Parts 1400—1499)
XV
Department of the Treasury (Parts 1500—1599)
XVII
Office of Federal Housing Enterprise Oversight, Department of Housing and Urban Development (Parts 1700—1799)
XVIII
Community Development Financial Institutions Fund, Department of the Treasury (Parts 1800—1899)

Title 13—Business Credit and Assistance
I
Small Business Administration (Parts 1—199)
III
Economic Development Administration, Department of Commerce (Parts 300—399)
IV
Emergency Steel Guarantee Loan Board, Department of Commerce (Parts 400—499)
V
Emergency Oil and Gas Guaranteed Loan Board, Department of Commerce (Parts 500—599)

Title 14—Aeronautics and Space
I
Federal Aviation Administration, Department of Transportation (Parts 1—199)
II
Office of the Secretary, Department of Transportation (Aviation Proceedings) (Parts 200—399)
III
Commercial Space Transportation, Federal Aviation Administration, Department of Transportation (Parts 400—499)
V
National Aeronautics and Space Administration (Parts 1200—1299)
VI
Air Transportation System Stabilization (Parts 1300—1399)

Title 15—Commerce and Foreign Trade
Subtitle A—Office of the Secretary of Commerce (Parts 0—29)
Subtitle B—Regulations Relating to Commerce and Foreign Trade
I
Bureau of the Census, Department of Commerce (Parts 30—199)
II
National Institute of Standards and Technology, Department of Commerce (Parts 200—299)
III
International Trade Administration, Department of Commerce (Parts 300—399)
IV
Foreign-Trade Zones Board, Department of Commerce (Parts 400—499)
VII
Bureau of Industry and Security, Department of Commerce (Parts 700—799)
VIII
Bureau of Economic Analysis, Department of Commerce (Parts 800—899)
IX
National Oceanic and Atmospheric Administration, Department of Commerce (Parts 900—999)
XI
Technology Administration, Department of Commerce (Parts 1100—1199)
XIII
East-West Foreign Trade Board (Parts 1300—1399)
XIV
Minority Business Development Agency (Parts 1400—1499)
Subtitle C—Regulations Relating to Foreign Trade Agreements
XX
Office of the United States Trade Representative (Parts 2000—2099)
Subtitle D—Regulations Relating to Telecommunications and Information
XXIII
National Telecommunications and Information Administration, Department of Commerce (Parts 2300—2399)

Title 16—Commercial Practices
I
Federal Trade Commission (Parts 0—999)
II
Consumer Product Safety Commission (Parts 1000—1799)

Title 17—Commodity and Securities Exchanges
I
Commodity Futures Trading Commission (Parts 1—199)
II
Securities and Exchange Commission (Parts 200—399)
IV
Department of the Treasury (Parts 400—499)

Title 18—Conservation of Power and Water Resources
I
Federal Energy Regulatory Commission, Department of Energy (Parts 1—399)
III
Delaware River Basin Commission (Parts 400—499)
VI
Water Resources Council (Parts 700—799)
VIII
Susquehanna River Basin Commission (Parts 800—899)
XIII
Tennessee Valley Authority (Parts 1300—1399)

Title 19—Customs Duties
I
Bureau of Customs and Border Protection, Department of Homeland Security; Department of the Treasury (Parts 0—199)
II
United States International Trade Commission (Parts 200—299)
III
International Trade Administration, Department of Commerce (Parts 300—399)
IV
Bureau of Immigration and Customs Enforcement, Department of Homeland Security (Parts 400—599)

Title 20—Employees' Benefits
I
Office of Workers' Compensation Programs, Department of Labor (Parts 1—199)
II
Railroad Retirement Board (Parts 200—399)
III
Social Security Administration (Parts 400—499)
IV
Employees Compensation Appeals Board, Department of Labor (Parts 500—599)
V
Employment and Training Administration, Department of Labor (Parts 600—699)
VI
Employment Standards Administration, Department of Labor (Parts 700—799)
VII
Benefits Review Board, Department of Labor (Parts 800—899)
VIII
Joint Board for the Enrollment of Actuaries (Parts 900—999)
IX
Office of the Assistant Secretary for Veterans' Employment and Training Service, Department of Labor (Parts 1000—1099)

Title 21—Food and Drugs
I
Food and Drug Administration, Department of Health and Human Services (Parts 1—1299)
II
Drug Enforcement Administration, Department of Justice (Parts 1300—1399)
III
Office of National Drug Control Policy (Parts 1400—1499)

Title 22—Foreign Relations
I
Department of State (Parts 1—199)
II
Agency for International Development (Parts 200—299)
III
Peace Corps (Parts 300—399)
IV
International Joint Commission, United States and Canada (Parts 400—499)
V
Broadcasting Board of Governors (Parts 500—599)
VII
Overseas Private Investment Corporation (Parts 700—799)
IX
Foreign Service Grievance Board (Parts 900—999)
X
Inter-American Foundation (Parts 1000—1099)
XI
International Boundary and Water Commission, United States and Mexico, United States Section (Parts 1100—1199)
XII
United States International Development Cooperation Agency (Parts 1200—1299)
XIII
Millenium Challenge Corporation (Parts 1300—1399)
XIV
Foreign Service Labor Relations Board; Federal Labor Relations Authority; General Counsel of the Federal Labor Relations Authority; and the Foreign Service Impasse Disputes Panel (Parts 1400—1499)
XV
African Development Foundation (Parts 1500—1599)
XVI
Japan-United States Friendship Commission (Parts 1600—1699)
XVII
United States Institute of Peace (Parts 1700—1799)

Title 23—Highways
I
Federal Highway Administration, Department of Transportation (Parts 1—999)
II
National Highway Traffic Safety Administration and Federal Highway Administration, Department of Transportation (Parts 1200—1299)
III
National Highway Traffic Safety Administration, Department of Transportation (Parts 1300—1399)

Title 24—Housing and Urban Development
Subtitle A—Office of the Secretary, Department of Housing and Urban Development (Parts 0—99)
Subtitle B—Regulations Relating to Housing and Urban Development
I
Office of Assistant Secretary for Equal Opportunity, Department of Housing and Urban Development (Parts 100—199)
II
Office of Assistant Secretary for Housing-Federal HousingCommissioner, Department of Housing and Urban Development (Parts 200—299)
III
Government National Mortgage Association, Department of Housing and Urban Development (Parts 300—399)
IV
Office of Housing and Office of Multifamily Housing Assistance Restructuring, Department of Housing and Urban Development (Parts 400—499)
V
Office of Assistant Secretary for Community Planning and Development, Department of Housing and Urban Development (Parts 500—599)
VI
Office of Assistant Secretary for Community Planning and Development, Department of Housing and Urban Development (Parts 600—699) [Reserved]
VII
Office of the Secretary, Department of Housing and Urban Development (Housing Assistance Programs and Public and Indian Housing Programs) (Parts 700—799)
VIII
Office of the Assistant Secretary for Housing—Federal Housing Commissioner, Department of Housing and Urban Development (Section 8 Housing Assistance Programs, Section 202 Direct Loan Program, Section 202 Supportive Housing for the Elderly Program and Section 811 Supportive Housing for Persons With Disabilities Program) (Parts 800—899)
IX
Office of Assistant Secretary for Public and Indian Housing, Department of Housing and Urban Development (Parts 900—1699)
X
Office of Assistant Secretary for Housing—Federal Housing Commissioner, Department of Housing and Urban Development (Interstate Land Sales Registration Program) (Parts 1700—1799)
XII
Office of Inspector General, Department of Housing and Urban Development (Parts 2000—2099)
XX
Office of Assistant Secretary for Housing—Federal Housing Commissioner, Department of Housing and Urban Development (Parts 3200—3899)
XXV
Neighborhood Reinvestment Corporation (Parts 4100—4199)

Title 25—Indians
I
Bureau of Indian Affairs, Department of the Interior (Parts 1—299)
II
Indian Arts and Crafts Board, Department of the Interior (Parts 300—399)
III
National Indian Gaming Commission, Department of the Interior (Parts 500—599)
IV
Office of Navajo and Hopi Indian Relocation (Parts 700—799)
V
Bureau of Indian Affairs, Department of the Interior, and Indian Health Service, Department of Health and Human Services (Part 900)
VI
Office of the Assistant Secretary-Indian Affairs, Department of the Interior (Parts 1000—1199)
VII
Office of the Special Trustee for American Indians, Department of the Interior (Parts 1200—1299)

Title 26—Internal Revenue
I
Internal Revenue Service, Department of the Treasury (Parts 1—899)

Title 27—Alcohol, Tobacco Products and Firearms
I
Alcohol and Tobacco Tax and Trade Bureau, Department of the Treasury (Parts 1—399)
II
Bureau of Alcohol, Tobacco, Firearms, and Explosives, Department of Justice (Parts 400—699)

Title 28—Judicial Administration
I
Department of Justice (Parts 0—299)
III
Federal Prison Industries, Inc., Department of Justice (Parts 300—399)
V
Bureau of Prisons, Department of Justice (Parts 500—599)
VI
Offices of Independent Counsel, Department of Justice (Parts 600—699)
VII
Office of Independent Counsel (Parts 700—799)
VIII
Court Services and Offender Supervision Agency for the District of Columbia (Parts 800—899)
IX
National Crime Prevention and Privacy Compact Council (Parts 900—999)
XI
Department of Justice and Department of State (Parts 1100—1199)

Title 29—Labor
Subtitle A—Office of the Secretary of Labor (Parts 0—99)
Subtitle B—Regulations Relating to Labor
I
National Labor Relations Board (Parts 100—199)
II
Office of Labor-Management Standards, Department of Labor (Parts 200—299)
III
National Railroad Adjustment Board (Parts 300—399)
IV
Office of Labor-Management Standards, Department of Labor (Parts 400—499)
V
Wage and Hour Division, Department of Labor (Parts 500—899)
IX
Construction Industry Collective Bargaining Commission (Parts 900—999)
X
National Mediation Board (Parts 1200—1299)
XII
Federal Mediation and Conciliation Service (Parts 1400—1499)
XIV
Equal Employment Opportunity Commission (Parts 1600—1699)
XVII
Occupational Safety and Health Administration, Department of Labor (Parts 1900—1999)
XX
Occupational Safety and Health Review Commission (Parts 2200—2499)
XXV
Employee Benefits Security Administration, Department of Labor (Parts 2500—2599)
XXVII
Federal Mine Safety and Health Review Commission (Parts 2700—2799)
XL
Pension Benefit Guaranty Corporation (Parts 4000—4999)

Title 30—Mineral Resources
I
Mine Safety and Health Administration, Department of Labor (Parts 1—199)
II
Minerals Management Service, Department of the Interior (Parts 200—299)
III
Board of Surface Mining and Reclamation Appeals, Department of the Interior (Parts 300—399)
IV
Geological Survey, Department of the Interior (Parts 400—499)
VII
Office of Surface Mining Reclamation and Enforcement, Department of the Interior (Parts 700—999)

Title 31—Money and Finance: Treasury
Subtitle A—Office of the Secretary of the Treasury (Parts 0—50)
Subtitle B—Regulations Relating to Money and Finance
I
Monetary Offices, Department of the Treasury (Parts 51—199)
II
Fiscal Service, Department of the Treasury (Parts 200—399)
IV
Secret Service, Department of the Treasury (Parts 400—499)
V
Office of Foreign Assets Control, Department of the Treasury (Parts 500—599)
VI
Bureau of Engraving and Printing, Department of the Treasury (Parts 600—699)
VII
Federal Law Enforcement Training Center, Department of the Treasury (Parts 700—799)
VIII
Office of International Investment, Department of the Treasury (Parts 800—899)
IX
Federal Claims Collection Standards (Department of the Treasury—Department of Justice) (Parts 900—999)

Title 32—National Defense
Subtitle A—Department of Defense
I
Office of the Secretary of Defense (Parts 1—399)
V
Department of the Army (Parts 400—699)
VI
Department of the Navy (Parts 700—799)
VII
Department of the Air Force (Parts 800—1099)
Subtitle B—Other Regulations Relating to National Defense
XII
Defense Logistics Agency (Parts 1200—1299)
XVI
Selective Service System (Parts 1600—1699)
XVII
Office of the Director of National Intelligence (Parts 1700—1799)
XVIII
National Counterintelligence Center (Parts 1800—1899)
XIX
Central Intelligence Agency (Parts 1900—1999)
XX
Information Security Oversight Office, National Archives and Records Administration (Parts 2000—2099)
XXI
National Security Council (Parts 2100—2199)
XXIV
Office of Science and Technology Policy (Parts 2400—2499)
XXVII
Office for Micronesian Status Negotiations (Parts 2700—2799)
XXVIII
Office of the Vice President of the United States (Parts 2800—2899)

Title 33—Navigation and Navigable Waters
I
Coast Guard, Department of Homeland Security (Parts 1—199)
II
Corps of Engineers, Department of the Army (Parts 200—399)
IV
Saint Lawrence Seaway Development Corporation, Department of Transportation (Parts 400—499)

Title 34—Education
Subtitle A—Office of the Secretary, Department of Education (Parts 1—99)
Subtitle B—Regulations of the Offices of the Department of Education
I
Office for Civil Rights, Department of Education (Parts 100—199)
II
Office of Elementary and Secondary Education, Department of Education (Parts 200—299)
III
Office of Special Education and Rehabilitative Services, Department of Education (Parts 300—399)
IV
Office of Vocational and Adult Education, Department of Education (Parts 400—499)
V
Office of Bilingual Education and Minority Languages Affairs, Department of Education (Parts 500—599)
VI
Office of Postsecondary Education, Department of Education (Parts 600—699)
VII
Office of Educational Research and Improvmeent, Department of Education [Reserved]
XI
National Institute for Literacy (Parts 1100—1199)
Subtitle C—Regulations Relating to Education
XII
National Council on Disability (Parts 1200—1299)
Title 35 [Reserved]

Title 36—Parks, Forests, and Public Property
I
National Park Service, Department of the Interior (Parts 1—199)
II
Forest Service, Department of Agriculture (Parts 200—299)
III
Corps of Engineers, Department of the Army (Parts 300—399)
IV
American Battle Monuments Commission (Parts 400—499)
V
Smithsonian Institution (Parts 500—599)
VI
[Reserved]
VII
Library of Congress (Parts 700—799)
VIII
Advisory Council on Historic Preservation (Parts 800—899)
IX
Pennsylvania Avenue Development Corporation (Parts 900—999)
X
Presidio Trust (Parts 1000—1099)
XI
Architectural and Transportation Barriers Compliance Board (Parts 1100—1199)
XII
National Archives and Records Administration (Parts 1200—1299)
XV
Oklahoma City National Memorial Trust (Parts 1500—1599)
XVI
Morris K. Udall Scholarship and Excellence in National Environmental Policy Foundation (Parts 1600—1699)

Title 37—Patents, Trademarks, and Copyrights
I
United States Patent and Trademark Office, Department of Commerce (Parts 1—199)
II
Copyright Office, Library of Congress (Parts 200—299)
III
Copyright Royalty Board, Library of Congress (Parts 301—399)
IV
Assistant Secretary for Technology Policy, Department of Commerce (Parts 400—499)
V
Under Secretary for Technology, Department of Commerce (Parts 500—599)

Title 38—Pensions, Bonuses, and Veterans' Relief
I
Department of Veterans Affairs (Parts 0—99)

Title 39—Postal Service
I
United States Postal Service (Parts 1—999)
III
Postal Regulatory Commission (Parts 3000—3099)

Title 40—Protection of Environment
I
Environmental Protection Agency (Parts 1—1099)
IV
Environmental Protection Agency and Department of Justice (Parts 1400—1499)
V
Council on Environmental Quality (Parts 1500—1599)
VI
Chemical Safety and Hazard Investigation Board (Parts 1600—1699)
VII
Environmental Protection Agency and Department of Defense; Uniform National Discharge Standards for Vessels of the Armed Forces (Parts 1700—1799)

Title 41—Public Contracts and Property Management
Subtitle B—Other Provisions Relating to Public Contracts
50
Public Contracts, Department of Labor (Parts 50-1—50-999)
51
Committee for Purchase From People Who Are Blind or Severely Disabled (Parts 51-1—51-99)
60
Office of Federal Contract Compliance Programs, Equal Employment Opportunity, Department of Labor (Parts 60-1—60-999)
61
Office of the Assistant Secretary for Veterans' Employment and Training Service, Department of Labor (Parts 61-1—61-999)
Chapters 62—100 [Reserved]
Subtitle C—Federal Property Management Regulations System
101
Federal Property Management Regulations (Parts 101-1—101-99)
102
Federal Management Regulation (Parts 102-1—102-299)
Chapters 103—104 [Reserved]
105
General Services Administration (Parts 105-1—105-999)
109
Department of Energy Property Management Regulations (Parts 109-1—109-99)
114
Department of the Interior (Parts 114-1—114-99)
115
Environmental Protection Agency (Parts 115-1—115-99)
128
Department of Justice (Parts 128-1—128-99)
Chapters 129—200 [Reserved]
Subtitle D—Other Provisions Relating to Property Management [Reserved]
Subtitle E—Federal Information Resources Management Regulations System [Reserved]
Subtitle F—Federal Travel Regulation System
300
General (Parts 300-1—300-99)
301
Temporary Duty (TDY) Travel Allowances (Parts 301-1—301-99)
302
Relocation Allowances (Parts 302-1—302-99)
303
Payment of Expenses Connected with the Death of Certain Employees (Part 303-1—303-99)
304
Payment of Travel Expenses from a Non-Federal Source (Parts 304-1—304-99)

Title 42—Public Health
I
Public Health Service, Department of Health and Human Services (Parts 1—199)
IV
Centers for Medicare & Medicaid Services, Department of Health and Human Services (Parts 400—499)
V
Office of Inspector General-Health Care, Department of Health and Human Services (Parts 1000—1999)

Title 43—Public Lands: Interior
Subtitle A—Office of the Secretary of the Interior (Parts 1—199)
Subtitle B—Regulations Relating to Public Lands
I
Bureau of Reclamation, Department of the Interior (Parts 200—499)
II
Bureau of Land Management, Department of the Interior (Parts 1000—9999)
III
Utah Reclamation Mitigation and Conservation Commission (Parts 10000—10010)

Title 44—Emergency Management and Assistance
I
Federal Emergency Management Agency, Department of Homeland Security (Parts 0—399)
IV
Department of Commerce and Department of Transportation (Parts 400—499)

Title 45—Public Welfare
Subtitle A—Department of Health and Human Services (Parts 1—199)
Subtitle B—Regulations Relating to Public Welfare
II
Office of Family Assistance (Assistance Programs), Administration for Children and Families, Department of Health and Human Services (Parts 200—299)
III
Office of Child Support Enforcement (Child Support Enforcement Program), Administration for Children and Families, Department of Health and Human Services (Parts 300—399)
IV
Office of Refugee Resettlement, Administration for Children and Families, Department of Health and Human Services (Parts 400—499)
V
Foreign Claims Settlement Commission of the United States, Department of Justice (Parts 500—599)
VI
National Science Foundation (Parts 600—699)
VII
Commission on Civil Rights (Parts 700—799)
VIII
Office of Personnel Management (Parts 800—899) [Reserved]
X
Office of Community Services, Administration for Children and Families, Department of Health and Human Services (Parts 1000—1099)
XI
National Foundation on the Arts and the Humanities (Parts 1100—1199)
XII
Corporation for National and Community Service (Parts 1200—1299)
XIII
Office of Human Development Services, Department of Health and Human Services (Parts 1300—1399)
XVI
Legal Services Corporation (Parts 1600—1699)
XVII
National Commission on Libraries and Information Science (Parts 1700—1799)
XVIII
Harry S. Truman Scholarship Foundation (Parts 1800—1899)
XXI
Commission on Fine Arts (Parts 2100—2199)
XXIII
Arctic Research Commission (Part 2301)
XXIV
James Madison Memorial Fellowship Foundation (Parts 2400—2499)
XXV
Corporation for National and Community Service (Parts 2500—2599)

Title 46—Shipping
I
Coast Guard, Department of Homeland Security (Parts 1—199)
II
Maritime Administration, Department of Transportation (Parts 200—399)
III
Coast Guard (Great Lakes Pilotage), Department of Homeland Security (Parts 400—499)
IV
Federal Maritime Commission (Parts 500—599)

Title 47—Telecommunication
I
Federal Communications Commission (Parts 0—199)
II
Office of Science and Technology Policy and National Security Council (Parts 200—299)
III
National Telecommunications and Information Administration, Department of Commerce (Parts 300—399)

Title 48—Federal Acquisition Regulations System
1
Federal Acquisition Regulation (Parts 1—99)
2
Defense Acquisition Regulations System, Department of Defense (Parts 200—299)
3
Department of Health and Human Services (Parts 300—399)
4
Department of Agriculture (Parts 400—499)
5
General Services Administration (Parts 500—599)
6
Department of State (Parts 600—699)
7
Agency for International Development (Parts 700—799)
8
Department of Veterans Affairs (Parts 800—899)
9
Department of Energy (Parts 900—999)
10
Department of the Treasury (Parts 1000—1099)
12
Department of Transportation (Parts 1200—1299)
13
Department of Commerce (Parts 1300—1399)
14
Department of the Interior (Parts 1400—1499)
15
Environmental Protection Agency (Parts 1500—1599)
16
Office of Personnel Management, Federal Employees Health Benefits Acquisition Regulation (Parts 1600—1699)
17
Office of Personnel Management (Parts 1700—1799)
18
National Aeronautics and Space Administration (Parts 1800—1899)
19
Broadcasting Board of Governors (Parts 1900—1999)
20
Nuclear Regulatory Commission (Parts 2000—2099)
21
Office of Personnel Management, Federal Employees Group Life Insurance Federal Acquisition Regulation (Parts 2100—2199)
23
Social Security Administration (Parts 2300—2399)
24
Department of Housing and Urban Development (Parts 2400—2499)
25
National Science Foundation (Parts 2500—2599)
28
Department of Justice (Parts 2800—2899)
29
Department of Labor (Parts 2900—2999)
30
Department of Homeland Security, Homeland Security Acquisition Regulation (HSAR) (Parts 3000—3099)
34
Department of Education Acquisition Regulation (Parts 3400—3499)
51
Department of the Army Acquisition Regulations (Parts 5100—5199)
52
Department of the Navy Acquisition Regulations (Parts 5200—5299)
53
Department of the Air Force Federal Acquisition Regulation Supplement [Reserved]
54
Defense Logistics Agency, Department of Defense (Parts 5400—5499)
57
African Development Foundation (Parts 5700—5799)
61
General Services Administration Board of Contract Appeals (Parts 6100—6199)
63
Department of Transportation Board of Contract Appeals (Parts 6300—6399)
99
Cost Accounting Standards Board, Office of Federal Procurement Policy, Office of Management and Budget (Parts 9900—9999)

Title 49—Transportation
Subtitle A—Office of the Secretary of Transportation (Parts 1—99)
Subtitle B—Other Regulations Relating to Transportation
I
Pipeline and Hazardous Materials Safety Administration, Department of Transportation (Parts 100—199)
II
Federal Railroad Administration, Department of Transportation (Parts 200—299)
III
Federal Motor Carrier Safety Administration, Department of Transportation (Parts 300—399)
IV
Coast Guard, Department of Homeland Security (Parts 400—499)
V
National Highway Traffic Safety Administration, Department of Transportation (Parts 500—599)
VI
Federal Transit Administration, Department of Transportation (Parts 600—699)
VII
National Railroad Passenger Corporation (AMTRAK) (Parts 700—799)
VIII
National Transportation Safety Board (Parts 800—999)
X
Surface Transportation Board, Department of Transportation (Parts 1000—1399)
XI
Research and Innovative Technology Administration, Department of Transportation [Reserved]
XII
Transportation Security Administration, Department of Homeland Security (Parts 1500—1699)

Title 50—Wildlife and Fisheries
I
United States Fish and Wildlife Service, Department of the Interior (Parts 1—199)
II
National Marine Fisheries Service, National Oceanic and Atmospheric Administration, Department of Commerce (Parts 200—299)
III
International Fishing and Related Activities (Parts 300—399)
IV
Joint Regulations (United States Fish and Wildlife Service, Department of the Interior and National Marine Fisheries Service, National Oceanic and Atmospheric Administration, Department of Commerce); Endangered Species Committee Regulations (Parts 400—499)
V
Marine Mammal Commission (Parts 500—599)
VI
Fishery Conservation and Management, National Oceanic and Atmospheric Administration, Department of Commerce (Parts 600—699)

CFR Index and Finding Aids
Subject/Agency Index
List of Agency Prepared Indexes
Parallel Tables of Statutory Authorities and Rules
List of CFR Titles, Chapters, Subchapters, and Parts
Alphabetical List of Agencies Appearing in the CFR

Alphabetical List of Agencies Appearing in the CFR
(Revised as of July 1, 2008)
Agency
CFR Title, Subtitle or Chapter
Administrative Committee of the Federal Register
1, I
Advanced Research Projects Agency
32, I
Advisory Council on Historic Preservation
36, VIII
African Development Foundation
22, XV
Federal Acquisition Regulation
48, 57
Agency for International Development
22, II
Federal Acquisition Regulation
48, 7
Agricultural Marketing Service
7, I, IX, X, XI
Agricultural Research Service
7, V
Agriculture Department
5, LXXIII
Agricultural Marketing Service
7, I, IX, X, XI
Agricultural Research Service
7, V
Animal and Plant Health Inspection Service
7, III; 9, I
Chief Financial Officer, Office of
7, XXX
Commodity Credit Corporation
7, XIV
Cooperative State Research, Education, and Extension Service
7, XXXIV
Economic Research Service
7, XXXVII
Energy, Office of
2, IX; 7, XXIX
Environmental Quality, Office of
7, XXXI
Farm Service Agency
7, VII, XVIII
Federal Acquisition Regulation
48, 4
Federal Crop Insurance Corporation
7, IV
Food and Nutrition Service
7, II
Food Safety and Inspection Service
9, III
Foreign Agricultural Service
7, XV
Forest Service
36, II
Grain Inspection, Packers and Stockyards Administration
7, VIII; 9, II
Information Resources Management, Office of
7, XXVII
Inspector General, Office of
7, XXVI
National Agricultural Library
7, XLI
National Agricultural Statistics Service
7, XXXVI
Natural Resources Conservation Service
7, VI
Operations, Office of
7, XXVIII
Procurement and Property Management, Office of
7, XXXII
Rural Business-Cooperative Service
7, XVIII, XLII
Rural Development Administration
7, XLII
Rural Housing Service
7, XVIII, XXXV
Rural Telephone Bank
7, XVI
Rural Utilities Service
7, XVII, XVIII, XLII
Secretary of Agriculture, Office of
7, Subtitle A
Transportation, Office of
7, XXXIII
World Agricultural Outlook Board
7, XXXVIII
Air Force Department
32, VII
Federal Acquisition Regulation Supplement
48, 53
Air Transportation Stabilization Board
14, VI
Alcohol and Tobacco Tax and Trade Bureau
27, I
Alcohol, Tobacco, Firearms, and Explosives, Bureau of
27, II
AMTRAK
49, VII
American Battle Monuments Commission
36, IV
American Indians, Office of the Special Trustee
25, VII
Animal and Plant Health Inspection Service
7, III; 9, I
Appalachian Regional Commission
5, IX
Architectural and Transportation Barriers Compliance Board
36, XI
Arctic Research Commission
45, XXIII
Armed Forces Retirement Home
5, XI
Army Department
32, V
Engineers, Corps of
33, II; 36, III
Federal Acquisition Regulation
48, 51
Benefits Review Board
20, VII
Bilingual Education and Minority Languages Affairs, Office of
34, V
Blind or Severely Disabled, Committee for Purchase From People Who Are
41, 51
Broadcasting Board of Governors
22, V
Federal Acquisition Regulation
48, 19
Census Bureau
15, I
Centers for Medicare & Medicaid Services
42, IV
Central Intelligence Agency
32, XIX
Chief Financial Officer, Office of
7, XXX
Child Support Enforcement, Office of
45, III
Children and Families, Administration for
45, II, III, IV, X
Civil Rights, Commission on
5, LXVIII; 45, VII
Civil Rights, Office for
34, I
Coast Guard
33, I; 46, I; 49, IV
Coast Guard (Great Lakes Pilotage)
46, III
Commerce Department
44, IV
Census Bureau
15, I
Economic Affairs, Under Secretary
37, V
Economic Analysis, Bureau of
15, VIII
Economic Development Administration
13, III
Emergency Management and Assistance
44, IV
Federal Acquisition Regulation
48, 13
Fishery Conservation and Management
50, VI
Foreign-Trade Zones Board
15, IV
Industry and Security, Bureau of
15, VII
International Trade Administration
15, III; 19, III
National Institute of Standards and Technology
15, II
National Marine Fisheries Service
50, II, IV, VI
National Oceanic and Atmospheric Administration
15, IX; 50, II, III, IV, VI
National Telecommunications and Information Administration
15, XXIII; 47, III
National Weather Service
15, IX
Patent and Trademark Office, United States
37, I
Productivity, Technology and Innovation, Assistant Secretary for
37, IV
Secretary of Commerce, Office of
15, Subtitle A
Technology, Under Secretary for
37, V
Technology Administration
15, XI
Technology Policy, Assistant Secretary for
37, IV
Commercial Space Transportation
14, III
Commodity Credit Corporation
7, XIV
Commodity Futures Trading Commission
5, XLI; 17, I
Community Planning and Development, Office of Assistant Secretary for
24, V, VI
Community Services, Office of
45, X
Comptroller of the Currency
12, I
Construction Industry Collective Bargaining Commission
29, IX
Consumer Product Safety Commission
5, LXXI; 16, II
Cooperative State Research, Education, and Extension Service
7, XXXIV
Copyright Office
37, II
Copyright Royalty Board
37, III
Corporation for National and Community Service
2, XXII; 45, XII, XXV
Cost Accounting Standards Board
48, 99
Council on Environmental Quality
40, V
Court Services and Offender Supervision Agency for the District of Columbia
28, VIII
Customs and Border Protection Bureau
19, I
Defense Contract Audit Agency
32, I
Defense Department
5, XXVI; 32, Subtitle A; 40, VII
Advanced Research Projects Agency
32, I
Air Force Department
32, VII
Army Department
32, V; 33, II; 36, III, 48, 51
Defense Acquisition Regulations System
48, 2
Defense Intelligence Agency
32, I
Defense Logistics Agency
32, I, XII; 48, 54
Engineers, Corps of
33, II; 36, III
National Imagery and Mapping Agency
32, I
Navy Department
32, VI; 48, 52
Secretary of Defense, Office of
2, XI; 32, I
Defense Contract Audit Agency
32, I
Defense Intelligence Agency
32, I
Defense Logistics Agency
32, XII; 48, 54
Defense Nuclear Facilities Safety Board
10, XVII
Delaware River Basin Commission
18, III
District of Columbia, Court Services and Offender Supervision Agency for the
28, VIII
Drug Enforcement Administration
21, II
East-West Foreign Trade Board
15, XIII
Economic Affairs, Under Secretary
37, V
Economic Analysis, Bureau of
15, VIII
Economic Development Administration
13, III
Economic Research Service
7, XXXVII
Education, Department of
5, LIII
Bilingual Education and Minority Languages Affairs, Office of
34, V
Civil Rights, Office for
34, I
Educational Research and Improvement, Office of
34, VII
Elementary and Secondary Education, Office of
34, II
Federal Acquisition Regulation
48, 34
Postsecondary Education, Office of
34, VI
Secretary of Education, Office of
34, Subtitle A
Special Education and Rehabilitative Services, Office of
34, III
Vocational and Adult Education, Office of
34, IV
Educational Research and Improvement, Office of
34, VII
Elementary and Secondary Education, Office of
34, II
Emergency Oil and Gas Guaranteed Loan Board
13, V
Emergency Steel Guarantee Loan Board
13, IV
Employee Benefits Security Administration
29, XXV
Employees' Compensation Appeals Board
20, IV
Employees Loyalty Board
5, V
Employment and Training Administration
20, V
Employment Standards Administration
20, VI
Endangered Species Committee
50, IV
Energy, Department of
5, XXIII; 10, II, III, X
Federal Acquisition Regulation
48, 9
Federal Energy Regulatory Commission
5, XXIV; 18, I
Property Management Regulations
41, 109
Energy, Office of
7, XXIX
Engineers, Corps of
33, II; 36, III
Engraving and Printing, Bureau of
31, VI
Environmental Protection Agency
2, XV; 5, LIV; 40, I, IV, VII
Federal Acquisition Regulation
48, 15
Property Management Regulations
41, 115
Environmental Quality, Office of
7, XXXI
Equal Employment Opportunity Commission
5, LXII; 29, XIV
Equal Opportunity, Office of Assistant Secretary for
24, I
Executive Office of the President
3, I
Administration, Office of
5, XV
Environmental Quality, Council on
40, V
Management and Budget, Office of
5, III, LXXVII; 14, VI; 48, 99
National Drug Control Policy, Office of
21, III
National Security Council
32, XXI; 47, 2
Presidential Documents
3
Science and Technology Policy, Office of
32, XXIV; 47, II
Trade Representative, Office of the United States
15, XX
Export-Import Bank of the United States
2, XXXV; 5, LII; 12, IV
Family Assistance, Office of
45, II
Farm Credit Administration
5, XXXI; 12, VI
Farm Credit System Insurance Corporation
5, XXX; 12, XIV
Farm Service Agency
7, VII, XVIII
Federal Acquisition Regulation
48, 1
Federal Aviation Administration
14, I
Commercial Space Transportation
14, III
Federal Claims Collection Standards
31, IX
Federal Communications Commission
5, XXIX; 47, I
Federal Contract Compliance Programs, Office of
41, 60
Federal Crop Insurance Corporation
7, IV
Federal Deposit Insurance Corporation
5, XXII; 12, III
Federal Election Commission
11, I
Federal Emergency Management Agency
44, I
Federal Employees Group Life Insurance Federal Acquisition Regulation
48, 21
Federal Employees Health Benefits Acquisition Regulation
48, 16
Federal Energy Regulatory Commission
5, XXIV; 18, I
Federal Financial Institutions Examination Council
12, XI
Federal Financing Bank
12, VIII
Federal Highway Administration
23, I, II
Federal Home Loan Mortgage Corporation
1, IV
Federal Housing Enterprise Oversight Office
12, XVII
Federal Housing Finance Board
12, IX
Federal Labor Relations Authority, and General Counsel of the Federal Labor Relations Authority
5, XIV; 22, XIV
Federal Law Enforcement Training Center
31, VII
Federal Management Regulation
41, 102
Federal Maritime Commission
46, IV
Federal Mediation and Conciliation Service
29, XII
Federal Mine Safety and Health Review Commission
5, LXXIV; 29, XXVII
Federal Motor Carrier Safety Administration
49, III
Federal Prison Industries, Inc.
28, III
Federal Procurement Policy Office
48, 99
Federal Property Management Regulations
41, 101
Federal Railroad Administration
49, II
Federal Register, Administrative Committee of
1, I
Federal Register, Office of
1, II
Federal Reserve System
12, II
Board of Governors
5, LVIII
Federal Retirement Thrift Investment Board
5, VI, LXXVI
Federal Service Impasses Panel
5, XIV
Federal Trade Commission
5, XLVII; 16, I
Federal Transit Administration
49, VI
Federal Travel Regulation System
41, Subtitle F
Fine Arts, Commission on
45, XXI
Fiscal Service
31, II
Fish and Wildlife Service, United States
50, I, IV
Fishery Conservation and Management
50, VI
Food and Drug Administration
21, I
Food and Nutrition Service
7, II
Food Safety and Inspection Service
9, III
Foreign Agricultural Service
7, XV
Foreign Assets Control, Office of
31, V
Foreign Claims Settlement Commission of the United States
45, V
Foreign Service Grievance Board
22, IX
Foreign Service Impasse Disputes Panel
22, XIV
Foreign Service Labor Relations Board
22, XIV
Foreign-Trade Zones Board
15, IV
Forest Service
36, II
General Services Administration
5, LVII; 41, 105
Contract Appeals, Board of
48, 61
Federal Acquisition Regulation
48, 5
Federal Management Regulation
41, 102
Federal Property Management Regulations
41, 101
Federal Travel Regulation System
41, Subtitle F
General
41, 300
Payment From a Non-Federal Source for Travel Expenses
41, 304
Payment of Expenses Connected With the Death of Certain Employees
41, 303
Relocation Allowances
41, 302
Temporary Duty (TDY) Travel Allowances
41, 301
Geological Survey
30, IV
Government Accountability Office
4, I
Government Ethics, Office of
5, XVI
Government National Mortgage Association
24, III
Grain Inspection, Packers and Stockyards Administration
7, VIII; 9, II
Harry S. Truman Scholarship Foundation
45, XVIII
Health and Human Services, Department of
2, III; 5, XLV; 45, Subtitle A,
Centers for Medicare & Medicaid Services
42, IV
Child Support Enforcement, Office of
45, III
Children and Families, Administration for
45, II, III, IV, X
Community Services, Office of
45, X
Family Assistance, Office of
45, II
Federal Acquisition Regulation
48, 3
Food and Drug Administration
21, I
Human Development Services, Office of
45, XIII
Indian Health Service
25, V
Inspector General (Health Care), Office of
42, V
Public Health Service
42, I
Refugee Resettlement, Office of
45, IV
Homeland Security, Department of
6, I
Coast Guard
33, I; 46, I; 49, IV
Coast Guard (Great Lakes Pilotage)
46, III
Customs and Border Protection Bureau
19, I
Federal Emergency Management Agency
44, I
Immigration and Customs Enforcement Bureau
19, IV
Immigration and Naturalization
8, I
Transportation Security Administration
49, XII
Housing and Urban Development, Department of
2, XXIV; 5, LXV; 24, Subtitle B
Community Planning and Development, Office of Assistant Secretary for
24, V, VI
Equal Opportunity, Office of Assistant Secretary for
24, I
Federal Acquisition Regulation
48, 24
Federal Housing Enterprise Oversight, Office of
12, XVII
Government National Mortgage Association
24, III
Housing—Federal Housing Commissioner, Office of Assistant Secretary for
24, II, VIII, X, XX
Housing, Office of, and Multifamily Housing Assistance Restructuring, Office of
24, IV
Inspector General, Office of
24, XII
Public and Indian Housing, Office of Assistant Secretary for
24, IX
Secretary, Office of
24, Subtitle A, VII
Housing—Federal Housing Commissioner, Office of Assistant Secretary for
24, II, VIII, X, XX
Housing, Office of, and Multifamily Housing Assistance Restructuring, Office of
24, IV
Human Development Services, Office of
45, XIII
Immigration and Customs Enforcement Bureau
19, IV
Immigration and Naturalization
8, I
Immigration Review, Executive Office for
8, V
Independent Counsel, Office of
28, VII
Indian Affairs, Bureau of
25, I, V
Indian Affairs, Office of the Assistant Secretary
25, VI
Indian Arts and Crafts Board
25, II
Indian Health Service
25, V
Industry and Security, Bureau of
15, VII
Information Resources Management, Office of
7, XXVII
Information Security Oversight Office, National Archives and Records Administration
32, XX
Inspector General
Agriculture Department
7, XXVI
Health and Human Services Department
42, V
Housing and Urban Development Department
24, XII
Institute of Peace, United States
22, XVII
Inter-American Foundation
5, LXIII; 22, X
Interior Department
American Indians, Office of the Special Trustee
25, VII
Endangered Species Committee
50, IV
Federal Acquisition Regulation
48, 14
Federal Property Management Regulations System
41, 114
Fish and Wildlife Service, United States
50, I, IV
Geological Survey
30, IV
Indian Affairs, Bureau of
25, I, V
Indian Affairs, Office of the Assistant Secretary
25, VI
Indian Arts and Crafts Board
25, II
Land Management, Bureau of
43, II
Minerals Management Service
30, II
National Indian Gaming Commission
25, III
National Park Service
36, I
Reclamation, Bureau of
43, I
Secretary of the Interior, Office of
2, XIV; 43, Subtitle A
Surface Mining and Reclamation Appeals, Board of
30, III
Surface Mining Reclamation and Enforcement, Office of
30, VII
Internal Revenue Service
26, I
International Boundary and Water Commission, United States and Mexico, United States Section
22, XI
International Development, United States Agency for
22, II
Federal Acquisition Regulation
48, 7
International Development Cooperation Agency, United States
22, XII
International Fishing and Related Activities
50, III
International Investment, Office of
31, VIII
International Joint Commission, United States and Canada
22, IV
International Organizations Employees Loyalty Board
5, V
International Trade Administration
15, III; 19, III
International Trade Commission, United States
19, II
Interstate Commerce Commission
5, XL
James Madison Memorial Fellowship Foundation
45, XXIV
Japan-United States Friendship Commission
22, XVI
Joint Board for the Enrollment of Actuaries
20, VIII
Justice Department
2, XXVII; 5, XXVIII; 28, I, XI; 40, IV
Alcohol, Tobacco, Firearms, and Explosives, Bureau of
27, II
Drug Enforcement Administration
21, II
Federal Acquisition Regulation
48, 28
Federal Claims Collection Standards
31, IX
Federal Prison Industries, Inc.
28, III
Foreign Claims Settlement Commission of the United States
45, V
Immigration Review, Executive Office for
8, V
Offices of Independent Counsel
28, VI
Prisons, Bureau of
28, V
Property Management Regulations
41, 128
Labor Department
5, XLII
Benefits Review Board
20, VII
Employee Benefits Security Administration
29, XXV
Employees' Compensation Appeals Board
20, IV
Employment and Training Administration
20, V
Employment Standards Administration
20, VI
Federal Acquisition Regulation
48, 29
Federal Contract Compliance Programs, Office of
41, 60
Federal Procurement Regulations System
41, 50
Labor-Management Standards, Office of
29, II, IV
Mine Safety and Health Administration
30, I
Occupational Safety and Health Administration
29, XVII
Public Contracts
41, 50
Secretary of Labor, Office of
29, Subtitle A
Veterans' Employment and Training Service, Office of the Assistant Secretary for
41, 61; 20, IX
Wage and Hour Division
29, V
Workers' Compensation Programs, Office of
20, I
Labor-Management Standards, Office of
29, II, IV
Land Management, Bureau of
43, II
Legal Services Corporation
45, XVI
Library of Congress
36, VII
Copyright Office
37, II
Copyright Royalty Board
37, III
Local Television Loan Guarantee Board
7, XX
Management and Budget, Office of
5, III, LXXVII; 14, VI; 48, 99
Marine Mammal Commission
50, V
Maritime Administration
46, II
Merit Systems Protection Board
5, II, LXIV
Micronesian Status Negotiations, Office for
32, XXVII
Millenium Challenge Corporation
22, XIII
Mine Safety and Health Administration
30, I
Minerals Management Service
30, II
Minority Business Development Agency
15, XIV
Miscellaneous Agencies
1, IV
Monetary Offices
31, I
Morris K. Udall Scholarship and Excellence in National Environmental Policy Foundation
36, XVI
National Aeronautics and Space Administration
2, XVIII; 5, LIX; 14, V
Federal Acquisition Regulation
48, 18
National Agricultural Library
7, XLI
National Agricultural Statistics Service
7, XXXVI
National and Community Service, Corporation for
45, XII, XXV
National Archives and Records Administration
2, XXVI; 5, LXVI; 36, XII
Information Security Oversight Office
32, XX
National Capital Planning Commission
1, IV
National Commission for Employment Policy
1, IV
National Commission on Libraries and Information Science
45, XVII
National Council on Disability
34, XII
National Counterintelligence Center
32, XVIII
National Credit Union Administration
12, VII
National Crime Prevention and Privacy Compact Council
28, IX
National Drug Control Policy, Office of
21, III
National Endowment for the Arts
2, XXXII
National Endowment for the Humanities
2, XXXIII
National Foundation on the Arts and the Humanities
45, XI
National Highway Traffic Safety Administration
23, II, III; 49, V
National Imagery and Mapping Agency
32, I
National Indian Gaming Commission
25, III
National Institute for Literacy
34, XI
National Institute of Standards and Technology
15, II
National Intelligence, Office of Director of
32, XVII
National Labor Relations Board
5, LXI; 29, I
National Marine Fisheries Service
50, II, IV, VI
National Mediation Board
29, X
National Oceanic and Atmospheric Administration
15, IX; 50, II, III, IV, VI
National Park Service
36, I
National Railroad Adjustment Board
29, III
National Railroad Passenger Corporation (AMTRAK)
49, VII
National Science Foundation
2, XXV; 5, XLIII; 45, VI
Federal Acquisition Regulation
48, 25
National Security Council
32, XXI
National Security Council and Office of Science and Technology Policy
47, II
National Telecommunications and Information Administration
15, XXIII; 47, III
National Transportation Safety Board
49, VIII
Natural Resources Conservation Service
7, VI
Navajo and Hopi Indian Relocation, Office of
25, IV
Navy Department
32, VI
Federal Acquisition Regulation
48, 52
Neighborhood Reinvestment Corporation
24, XXV
Northeast Interstate Low-Level Radioactive Waste Commission
10, XVIII
Nuclear Regulatory Commission
5, XLVIII; 10, I
Federal Acquisition Regulation
48, 20
Occupational Safety and Health Administration
29, XVII
Occupational Safety and Health Review Commission
29, XX
Offices of Independent Counsel
28, VI
Oklahoma City National Memorial Trust
36, XV
Operations Office
7, XXVIII
Overseas Private Investment Corporation
5, XXXIII; 22, VII
Patent and Trademark Office, United States
37, I
Payment From a Non-Federal Source for Travel Expenses
41, 304
Payment of Expenses Connected With the Death of Certain Employees
41, 303
Peace Corps
22, III
Pennsylvania Avenue Development Corporation
36, IX
Pension Benefit Guaranty Corporation
29, XL
Personnel Management, Office of
5, I, XXXV; 45, VIII
Federal Acquisition Regulation
48, 17
Federal Employees Group Life Insurance Federal Acquisition Regulation
48, 21
Federal Employees Health Benefits Acquisition Regulation
48, 16
Pipeline and Hazardous Materials Safety Administration
49, I
Postal Regulatory Commission
5, XLVI; 39, III
Postal Service, United States
5, LX; 39, I
Postsecondary Education, Office of
34, VI
President's Commission on White House Fellowships
1, IV
Presidential Documents
3
Presidio Trust
36, X
Prisons, Bureau of
28, V
Privacy and Civil Liberties Oversight Board
6, X
Procurement and Property Management, Office of
7, XXXII
Productivity, Technology and Innovation, Assistant Secretary
37, IV
Public Contracts, Department of Labor
41, 50
Public and Indian Housing, Office of Assistant Secretary for
24, IX
Public Health Service
42, I
Railroad Retirement Board
20, II
Reclamation, Bureau of
43, I
Refugee Resettlement, Office of
45, IV
Relocation Allowances
41, 302
Research and Innovative Technology Administration
49, XI
Rural Business-Cooperative Service
7, XVIII, XLII
Rural Development Administration
7, XLII
Rural Housing Service
7, XVIII, XXXV
Rural Telephone Bank
7, XVI
Rural Utilities Service
7, XVII, XVIII, XLII
Saint Lawrence Seaway Development Corporation
33, IV
Science and Technology Policy, Office of
32, XXIV
Science and Technology Policy, Office of, and National Security Council
47, II
Secret Service
31, IV
Securities and Exchange Commission
17, II
Selective Service System
32, XVI
Small Business Administration
2, XXVII; 13, I
Smithsonian Institution
36, V
Social Security Administration
2, XXIII; 20, III; 48, 23
Soldiers' and Airmen's Home, United States
5, XI
Special Counsel, Office of
5, VIII
Special Education and Rehabilitative Services, Office of
34, III
State Department
2, VI; 22, I; 28, XI
Federal Acquisition Regulation
48, 6
Surface Mining and Reclamation Appeals, Board of
30, III
Surface Mining Reclamation and Enforcement, Office of
30, VII
Surface Transportation Board
49, X
Susquehanna River Basin Commission
18, VIII
Technology Administration
15, XI
Technology Policy, Assistant Secretary for
37, IV
Technology, Under Secretary for
37, V
Tennessee Valley Authority
5, LXIX; 18, XIII
Thrift Supervision Office, Department of the Treasury
12, V
Trade Representative, United States, Office of
15, XX
Transportation, Department of
2, XII; 5, L
Commercial Space Transportation
14, III
Contract Appeals, Board of
48, 63
Emergency Management and Assistance
44, IV
Federal Acquisition Regulation
48, 12
Federal Aviation Administration
14, I
Federal Highway Administration
23, I, II
Federal Motor Carrier Safety Administration
49, III
Federal Railroad Administration
49, II
Federal Transit Administration
49, VI
Maritime Administration
46, II
National Highway Traffic Safety Administration
23, II, III; 49, V
Pipeline and Hazardous Materials Safety Administration
49, I
Saint Lawrence Seaway Development Corporation
33, IV
Secretary of Transportation, Office of
14, II; 49, Subtitle A
Surface Transportation Board
49, X
Transportation Statistics Bureau
49, XI
Transportation, Office of
7, XXXIII
Transportation Security Administration
49, XII
Transportation Statistics Bureau
49, XI
Travel Allowances, Temporary Duty (TDY)
41, 301
Treasury Department
5, XXI; 12, XV; 17, IV; 31, IX
Alcohol and Tobacco Tax and Trade Bureau
27, I
Community Development Financial Institutions Fund
12, XVIII
Comptroller of the Currency
12, I
Customs and Border Protection Bureau
19, I
Engraving and Printing, Bureau of
31, VI
Federal Acquisition Regulation
48, 10
Federal Claims Collection Standards
31, IX
Federal Law Enforcement Training Center
31, VII
Fiscal Service
31, II
Foreign Assets Control, Office of
31, V
Internal Revenue Service
26, I
International Investment, Office of
31, VIII
Monetary Offices
31, I
Secret Service
31, IV
Secretary of the Treasury, Office of
31, Subtitle A
Thrift Supervision, Office of
12, V
Truman, Harry S. Scholarship Foundation
45, XVIII
United States and Canada, International Joint Commission
22, IV
United States and Mexico, International Boundary and Water Commission, United States Section
22, XI
Utah Reclamation Mitigation and Conservation Commission
43, III
Veterans Affairs Department
2, VIII; 38, I
Federal Acquisition Regulation
48, 8
Veterans' Employment and Training Service, Office of the Assistant Secretary for
41, 61; 20, IX
Vice President of the United States, Office of
32, XXVIII
Vocational and Adult Education, Office of
34, IV
Wage and Hour Division
29, V
Water Resources Council
18, VI
Workers' Compensation Programs, Office of
20, I
World Agricultural Outlook Board
7, XXXVIII
30 CFR (7-1-08 Edition)
List of CFR Sections Affected

List of CFR Sections Affected
All changes in this volume of the Code of Federal Regulations that were made by documents published in the Federal Register since January 1, 2001, are enumerated in the following list. Entries indicate the nature of the changes effected. Page numbers refer to Federal Register pages. The user should consult the entries for chapters and parts as well as sections for revisions.
For the period before January 1, 2001, see the “List of Sections Affected, 1949-1963, 1964-1972, 1973-1985, and 1986-2000,” published in 11 separate volumes.
2001
30 CFR
66 FR
Page
Chapter II
206.251Amended
45769
206.254(a) removed; (b) designation removed and amended
45769
206.257(d)(3) amended
45769
206.259(a)(1), (b)(1), (c)(1)(i), (2)(i), (d)(1), (e)(1) and (2) amended
45769
206.262(a)(1), (b)(1), (c)(1)(i), (2)(i), (d)(1), (e)(1) and (2) amended
45769
206.263Removed
45769
206.453(a) removed; (b) designation removed and amended
45769
206.456(d)(3) amended
45769
206.458(c)(1)(i), (2)(i), (4), (d)(1), (e)(1) and (2) amended
45769
206.461(c)(1)(i), (2)(i), (4), (d)(1), (e)(1) and (2) amended
45769
206.462Removed
45769
208.4(b)(4) removed
28657
210.10Nomenclature change; (a) and (d) revised; (b)(2) and (3) amended; (b)(6), (c)(4), (11) and (12) removed; (c)(5) through (10) and (13) through through (20) redesignated as new (c)(4) through (9) and (10) through (17); (b)(6), (7), (8) and new (c)(18) through (21) added
45769
210.200—210.204 (Subpart E)Removed; new 210.200—210.206 (Subpart E) added
45771
210.201(c)(3)(i) corrected
50827
216.2Amended
45773
216.6Amended
45773
216.20Amended
45773
216.40(d) removed; (e), (f) and (g) redesignated as (d), (e) and (f)
45773
216.200—216.204 (Subpart E)removed
45773
218Authority citation revised
45773
218.40(c) revised
45773
218.51(d)(2), (3) and (e) amended
45773
218.151Heading, (a) and (b) revised; introductory text added; (c) and (d) removed; (e) redesignated as new (c)
11518
218.201Revised
45773
218.203(a) and (b) amended
45773
(b) corrected
50827
256.14Removed
32904
256.40Introductory text revised
11518
256.52(b)(1) revised; (d), (e), (g) introductory text, (1) and (2) amended
60150
256.58Revised
60150
260Revised
11518
2002
30 CFR
67 FR
Page
Chapter II
201.100Heading amended
19111
203.0Amended
1872
203.2Revised
1872
203.4Revised
1873
203.60Revised
1875
203.62Introductory text and (c) revised
1875
203.63Introductory text, (a), (b) and (c) redesignated as (a), (1), (2) and (3); new (b) added
1875
203.64Heading revised; introductory text amended
1875
203.65(b) revised
1875
203.66Revised
1875
203.67Revised
1876
203.68(b) revised
1876
203.69Introductory text and (b) through (e) revised; (f) added
1876
203.70Revised
1876
203.71Introductory text, (a), (b) and (c) revised
1877
203.74(b) and (c) redesignated as (c) and (d); introductory text, new (c) and (d) revised; new (b) added
1878
203.76(a), (b) and (c) revised
1878
203.77Revised
1878
203.78Introductory text, (a)(1), (b)(1) and (f) revised
1878
203.80Added
1879
203.81(a) and (c) revised
1879
203.83(c) revised
1879
203.86(b)(6), (7), (d)(6) and (7) amended; (b)(8) and (d)(8) added; (c)(4) revised
1879
203.87(a)(1) and (d) revised
1880
203.89(a) revised
1880
203.91Amended
1880
206.52(e)(2) amended
19111
206.103(b)(2)(iii) amended
19111
206.152(e)(3) amended
19111
206.153(e)(3) amended
19111
206.250(c) amended
19111
206.352(e)(3) amended
19111
206.355(e)(3) amended
19111
206.356(d)(3) amended
19111
212Authority citation revised
19111
212.51(a) amended
19111
212.351(a) and (c) amended
19111
216.6Amended
19111
216.15(a) and (b) amended
19111
216.16(a) and (b) amended
19111
216.21Amended
19111
216.30Amended
19112
217.200Amended
19112
218.51(g)(1) and (h)(2) amended
19112
218.53(b) amended
19112
218.102(b) amended
19112
218.150(c) amended
19112
218.151(c) amended
19112
218.155(a) and (d)(3) amended
19112
218.202(b) amended
19112
218.302(b) amended
19112
219.102Amended
19112
220.011(c)(1) amended
19112
227.103Amended
19112
227.110(b) amended
19112
227.401(f) amended
19112
227.501(c) amended
19112
228.6Amended
19112
230Removed
19112
241Authority citation revised
19112
241.54Amended
19112
241.56(b) amended
19113
241.62Amended
19113
241.64(b) amended
19113
243Heading revised
19113
243.3Amended
19113
250.102(b) table amended; eff. 7-16-02
35405
250.175Existing text designated as (a); (b) added
44360
250.198(d) table and (e) table amended
51759
250.199(e) table amended; eff. 7-16-02
35405
250.700—250.704 (Subpart G)Removed; eff. 7-16-02
35405
250.802(b) and (e)(2) revised
51759
250.803(a), (b)(4) introductory text, (5)(i), (7), (9)(v) and (c)(2) introductory text revised; (b)(2)(i), (10) and (d) amended
51759
250.804(a)(3) introductory text revised; (a)(4) through (11) redesignated as (a)(5) through (12); new (a)(4) added; (a) introductory text, new (a)(5) and (10) amended
51760
250.913Removed; eff. 7-16-02
35405
250.1001Amended; eff. 7-16-02
35405
250.1002(d) amended
51760
250.1004(b)(9) amended
51760
250.1006Revised; eff. 7-16-02
35405
250.1007(c) removed; eff. 7-16-02
35406
250.1014Amended; eff. 7-16-02
35406
250.1604(c) and (d) amended
51760
250.1628(c) and (d)(2) revised
51760
250.1629(b)(2) and (4)(v) revised
51760
250.1630(a) introductory text and (2) introductory text revised; (a)(3), (4) and (5) redesignated as (a)(4), (5) and (6); new (a)(3) added
51761
250.1700—250.1754 (Subpart Q)Added; eff. 7-16-02
35406
250.1700(c) corrected
66047
250.1704Table correctly added
44265
(f) correctly designated as (g); new (f) correctly added; table corrected; new (g) correctly revised
66047
250.1712Introductory text corrected; (e) and (f)(14) correctly revised
66048
250.1715Table correctly added
44265
(a)(1) through (4) correctly revised; (a)(10) correctly added
66048
250.1717Introductory text correctly revised
66049
250.1721Undesignated center heading, heading and introductory text corrected; (a) and (g) introductory text amended
66049
250.1722Introductory text, (c) and (g) introductory text corrected; (a) and (d) introductory text amended
66049
250.1723Introductory text corrected; (b) amended
66049
250.1726Introductory text correctly revised
66049
250.1740(a) correctly removed; (b) correctly redesignated as (a); new (b) correctly added; (a) introductory text and (c) introductory text correctly revised; (c)(3) corrected
66049
250.1741(g) table correctly added
44266
(b) correctly revised; (g) table corrected
66049
250.1742Table correctly added
44266
250.1743(a) amended; (b) corrected
66049
256.56(a)(1) amended; eff. 7-16-02
35412
256.62(e)(2) amended; eff. 7-16-02
35412
260.114(d) revised
57739
260.124(b)(1) revised
57739
280Revised
46858
Chapter VI
ChapterVI Removed
30803
2003
30 CFR
68 FR
Page
Chapter II
250.102(b)(1) revised
8422
250.105Amended
8422
250.108Revised
7426
250.114(c) revised
43298
250.160(f) through (i) added
69311
250.198(e) table corrected
46
(e) table amended
7427, 8422, 19355, 43298
250.199(e) table amended
8422
250.203(b)(5)(i), (ii) and (p) amended
8422
250.204(b)(2)(i), (ii) and (t) amended
8422
250.400Revised
8423
250.401Revised
8423
250.402Revised
8423
250.403Revised
8423
250.404Revised
8423
250.405Revised
8423
250.406Revised
8423
250.407Revised
8423
250.408Revised
8423
250.409Revised
8423
250.410Revised
8423
250.411Revised
8423
250.412Revised
8423
250.413Revised
8423
250.414Revised
8423
250.415Revised
8423
250.416Revised
8423
250.417Redesignated as 250.490; new 250.417 added
8423
250.418Added
8423
250.420Added
8423
250.421Added
8423
250.422Added
8423
250.423Added
8423
250.424Added
8423
250.425Added
8423
250.426Added
8423
250.427Added
8423
250.428Added
8423
250.430Added
8423
250.431Added
8423
250.432Added
8423
250.433Added
8423
250.434Added
8423
250.440Added
8423
250.441Added
8423
250.442Added
8423
250.443Added
8423
250.444Added
8423
250.445Added
8423
250.446Added
8423
250.447Added
8423
250.448Added
8423
250.449Added
8423
250.450Added
8423
250.451Added
8423
250.455Added
8423
250.456Added
8423
(i) corrected
14274
250.457Added
8423
250.458Added
8423
250.459Added
8423
250.460Added
8423
250.461Added
8423
250.462Added
8423
250.463Added
8423
250.465Added
8423
250.466Added
8423
250.467Added
8423
250.468Added
8423
250.469Added
8423
250.490Redesignated from 250.417; undesignated center heading added
8423
(g)(4)(iv), (j)(13)(ii) and (p)(2) revised
8434
250.504Amended
8434
250.513(a) and (b)(4) amended
8434
250.515(b) revised
8434
250.604Amended
8435
250.613(b)(3) amended
8435
250.615(b) revised
8435
250.803(b)(9)(v) revised
43298
(b)(7) revised
65172
250.804(a)(5) and (6) corrected
46
250.807Amended
8435
250.900(g) revised
19355
250.912(a) amended
19355
(a) amended
41078
Correctly amended
41861
250.1009(a)(1), (2), (b)(1) introductory text, (i), (ii), (2) introductory text, (i), (ii), (iii), (3), (4), (c) introductory text, (1) through (6), (7)(i), (ii) introductory text, (A), (B), (8), (9), (d) and (e) redesignated as (a), (b), 250.1011 (a) introductory text, (1), (2), (b) introductory text, (1), (2), (3), (c), (d), 250.1010 introductory text, (a), 250.1012, 250.1010 (b) through (e), (f)(1), (2) introductory text, (i), (ii), (g), (h), 250.1013 and 250.1014
69311
250.1010Redesignated as 250.1015; new 250.1010 introductory text, (a) through (e), (f)(1), (2) introductory text, (i), (ii), (g) and (h) redesignated from 250.1009 (c) introductory text, (1), (3) through (6), (7)(i), (ii) introductory text, (A), (B), (8) and (9)
69312
250.1011Redesignated as 250.1016; new 250.1011 (a) introductory text, (1), (2), (b) introductory text, (1), (2), (3), (c) and (d) redesignated from 250.1009(b)(1) introductory text, (i)(ii), (2) introductory text, (i), (ii), (iii), (3) and (4)
69311
Heading for new 250.1011 revised
69312
250.1012Redesignated as 250.1017; new 250.1012 redesignated from 250.1009(c)(2)
69311
New 250.1012 revised
69312
250.1013Redesignated as 250.1018; new 250.1013 redesignated from 250.1009(d)
69311
Heading for new 250.1013 revised
69312
250.1014Redesignated as 250.1019; new 250.1014 redesignated from 250.1009(e)
69311
Heading for new 250.1014 revised
69312
250.1015Redesignated from 250.1010
69311
Heading revised
69312
250.1016Redesignated from 250.1011
69311
Heading revised
69312
250.1017Redesignated from 250.1012
69311
Heading revised
69312
250.1018Redesignated from 250.1013
69311
Heading revised
69313
250.1019Redesignated from 250.1014; heading revised
69312
250.1105(f)(1)(i) amended
8435
250.1403Revised
61624
250.1604(b) amended
8435
250.1612Amended
8435
250.1614(b) amended
8435
250.1629(b)(4)(v) revised
43298
2004
30 CFR
69 FR
Page
Chapter II
203.0Amended
3509, 24053
Regulation at 69 FR 3509 eff. date corrected to 5-3-04
24052
Regulation at 69 FR 24053 eff. date corrected to 5-3-04
25500
203.4Introductory text revised
3509
203.5Added
3509
Regulation at 69 FR 3509 eff. date corrected to 5-3-04
24052
203.40Section and undesignated center heading added
3510
Regulation at 69 FR 3510 eff. date corrected to 5-3-04
24052
203.41Added
3510
Regulation at 69 FR 3510 eff. date corrected to 5-3-04
24052
(b) and (d) amended
24053
Regulation at 69 FR 24053 eff. date corrected to 5-3-04
25500
203.42Added
3510
Regulation at 69 FR 3510 eff. date corrected to 5-3-04
24052
(a)(1) and (b) introductory text revised
24054
Regulation at 69 FR 24054 eff. date corrected to 5-3-04
25500
203.43Added
3510
Regulation at 69 FR 3510 eff. date corrected to 5-3-04
24052
(d) and (e) introductory text revised
24054
Regulation at 69 FR 24054 eff. date corrected to 5-3-04
25500
203.44Added
3510
Regulation at 69 FR 3510 eff. date corrected to 5-3-04
24052
(b) amended; (e) introductory text revised
24054
Regulation at 69 FR 24054 eff. date corrected to 5-3-04
25500
203.45Added
3510
Regulation at 69 FR 3510 eff. date corrected to 5-3-04
24052
203.46Added
3510
Regulation at 69 FR 3510 eff. date corrected to 5-3-04
24052
(c) revised
24054
Regulation at 69 FR 24054 eff. date corrected to 5-3-04
25500
203.47Added
3510
Regulation at 69 FR 3510 eff. date corrected to 5-3-04
24052
203.48Added
3510
Regulation at 69 FR 3510 eff. date corrected to 5-3-04
24052
204Added
55088
Notice of decision by States
68805
206.101Amended; eff. 7-6-04
24975
Regulation at 69 FR 24975 eff. date corrected to 8-1-04
29432
206.103(b), (c), (d), (e) introductory text, (1)(ii) and (iii) revised; eff. 7-6-04
24976
Regulation at 69 FR 24976 eff. date corrected to 8-1-04
29432
206.104Heading, (a) introductory text, (3), (c) and (d) revised; eff. 7-6-04
24976
Regulation at 69 FR 24976 eff. date corrected to 8-1-04
29432
206.109(b) revised; eff. 7-6-04
24976
Regulation at 69 FR 24976 eff. date corrected to 8-1-04
29432
206.110(a) revised; (b) through (e) redesignated as (d) through (g); new (b) and (c) added; eff. 7-6-04
24977
Regulation at 69 FR 24977 eff. date corrected to 8-1-04
29432
206.111Heading, (a), (b) introductory text, (h)(5) and (i)(2) revised; (b)(6) and (7) added; eff. 7-6-04
24977
Regulation at 69 FR 24977 eff. date corrected to 8-1-04
29432
206.112Revised; eff. 7-6-04
24978
Regulation at 69 FR 24978 eff. date corrected to 8-1-04
29432
206.118Removed; eff. 7-6-04
24979
Regulation at 69 FR 24979 eff. date corrected to 8-1-04
29432
206.119(c) revised; eff. 7-6-04
24979
Regulation at 69 FR 24979 eff. date corrected to 8-1-04
29432
206.121Removed; eff. 7-6-04
24979
Regulation at 69 FR 24979 eff. date corrected to 8-1-04
29432
250.160(i) revised
29433
250.198Nomenclature change
18803
250.1012(e) revised
29433
2005
30 CFR
70 FR
Page
Chapter II
203.40Introductory text and (a) revised
22252
204Policy statement
72381
206.150(b) revised
11877
206.151Amended
11878
206.157(b)(2)(v), (5), (c), (f) introductory text, (1), (7) and (g)(5) revised; (f)(10), (g)(6), (7) and (8) added; (g)(4) amended
11878
216.53(e) and (f) added
56852
218.50(d) and (e) added
56853
250Authority citation revised
49875
Regulation at 70 FR 49875 eff. date delayed
56119
250.102(b) table amended
51500
Regulation at 70 FR 51500 eff. date delayed
56853
250.105Amended
41573, 51500
Regulation at 70 FR 51500 eff. date delayed
56853
250.125Undesignated center heading and section added
49875
Regulation at 70 FR 49875 eff. date delayed
56119
250.143(d) added
49876
Regulation at 70 FR 49876 eff. date delayed
56119
250.171Revised
49876
Regulation at 70 FR 49876 eff. date delayed
56119
250.175(c) added
74663
250.198(e) table amended
7403, 41573
250.199(e) table amended
41574, 51500
Regulation at 70 FR 51500 eff. date delayed
56853
250.200—250.299 (Subpart B)Revised
51501
Regulation at 70 FR 51501 eff. date delayed
56853
250.303(b)(2) and (d) amended
51518
Regulation at 70 FR 51518 eff. date delayed
56853
250.304(a)(6) and (b) amended
51519
Regulation at 70 FR 51519 eff. date delayed
56853
250.800Existing text designated as (a); (b) added
41574
250.803(b)(1) introductory text revised
7403
(a) revised; (b)(2)(iii) added
41575
250.900—250.921 (Subpart I)Revised
41575
250.1002(b)(4) and (5) added
41583
250.1007(a)(4) revised
41583
250.1015(a) revised
49876
Regulation at 70 FR 49876 eff. date delayed
56119
(e) added
61893
250.1018(b) revised
49876
Regulation at 70 FR 49876 eff. date delayed
56119
(c) added
61893
250.1101(f) added
49876
Regulation at 70 FR 49876 eff. date delayed
56119
250.1106(d) added
49876
Regulation at 70 FR 49876 eff. date delayed
56119
250.1303(d) added
49876
Regulation at 70 FR 49876 eff. date delayed
56119
250.1605(d) amended
51519
Regulation at 70 FR 51519 eff. date delayed
56853
250.1629(b)(1) introductory text revised
7403
256Authority citation revised
49876
256.63Added
49876
Regulation at 70 FR 49876 eff. date delayed
56119
256.64(a)(8) revised
49877
Regulation at 70 FR 49877 eff. date delayed
56119
(a)(9) added
61893
282.28(a) amended
51519
Regulation at 70 FR 51519 eff. date delayed
56853
2006
30 CFR
71 FR
Page
Chapter II
201—243 (Subchapter A)Heading revised
51751
218.500—218.580 (Subpart H)Added
51751
241.51(c) removed; (b) revised
51752
241.61Revised
51752
250Nomenclature change
46399, 46400
250.105Amended
23862
250.125(a) table and (b) revised; (c) added
40909
250.126Added
40911
250.186Redesignated from 250.190; eff. 7-17-06
19644
250.187Added; eff. 7-17-06
19644
250.188Added; eff. 7-17-06
19644
250.189Added; eff. 7-17-06
19644
250.190Redesignated as 250.186; new 250.190 added; eff. 7-17-06
19644
250.191Revised; eff. 7-17-06
19645
250.194Heading and (a) introductory text revised
23862
250.195Redesignated as 250.196; new 250.195 added
23862
250.196(b)(1) removed; (b)(2) through (10) redesignated as (b)(1) through (9); heading, introductory text, (b) introductory text and new (9) revised
16039
Redesignated as 250.197; new 250.196 redesignated from 250.195
23862
250.197Redesignated from 250.196; (a) and (b)(7) revised; (b) table amended
23862
250.198(e) table amended
40911
250.199(e) revised
23863
250.211(d) added
40911
250.235Second (a) correctly designated as (c)
12438
250.241(e) added
40911
250.292(n) and (o) revised; (p) added
40911
250.296(a) amended
40911
250.410Introductory text and (d) revised
40911
250.465(b)(1) revised
40911
250.490(l) revised; eff. 7-17-06
19645
250.513(d) amended; eff. 7-17-06
19646
(a) amended; (b) introductory text, (3) and (4) revised; (b)(5) added
40911
250.601Amended
11313
250.613(a) amended; (b) introductory text, (2) and (3) revised; (b)(4) added
40912
250.615(e) revised
11313
(e)(1) table corrected
29710
250.616(d) and (e) redesignated as (f) and (g); new (d) and (e) added; (a) and new (f) revised
11313
250.802(e)(7) added
40912
250.900(b)(2) corrected
16859
250.910(b)(2)(i) corrected
28080
250.905Introductory text revised; table amended; (k) added
40912
250.1000(b) revised
40912
250.1008(e) revised
40912
250.1102(a)(9), (b)(8) and (9) amended; eff. 7-17-06
19646
250.1202(a)(1) revised
40912
250.1203(b)(1) revised
40912
250.1204(a)(1) revised
40913
250.1402Amended
23864
250.1617(d) amended; eff. 7-17-06
19646
(a) revised
40913
250.1618Heading and (a) revised
40913
250.1704(g) revised
40913
250.1727Introductory text revised
40913
250.1751(a) introductory text revised
40913
250.1752(a) introductory text revised
40913
251Authority citation revised
40913
251.5(a) revised
40913
251.14(b) introductory text and (1) table revised; (b)(3) added
16039
(b)(1) table corrected
62050
254Nomenclature change
46400
280Authority citation revised
40914
280.12(a) revised
40914
290Authority citation revised
51752
290.100—290.111 (Subpart B)Heading revised
51752
290.100Revised
51752
290.102Amended
51752
290.111Removed
51752
2007
30 CFR
72 FR
Page
Chapter II
202.351Revised
24458
202.353Revised
24458
203.44(a) amended
25198
206.50Revised
71241
206.51Revised
71241
206.52Revised
71241
206.53Revised
71241
206.54Redesignated as 206.56; new 206.54 added
71241
206.55Redesignated as 206.57; new 206.55 added
71241
206.56Redesignated from 206.54; (a), (b)(1) and (c) amended
71241
206.57Redesignated from 206.55
71241
206.58Added
71244
206.59Added
71244
206.60Added
71244
206.61Added
71244
206.62Added
71244
206.350—206.366 (Subpart H)Revised
24459
210.352Removed; new 210.352 redesignated from 210.353
24467
210.353Redesignated as 210.352; redesignated from 210.354
24467
210.354Redesignated as 210.353; redesignated from 210.355 and revised
24467
210.355Redesignated as 210.354
24467
217.300—217.302 (Subpart G)Added
24468
218Heading revised
24468
218.303Added
24468
218.304Added
24468
218.305Added
24468
218.306Added
24468
218.307Added
24468
250.102(b) table revised
25198
250.108(c) revised
12092
250.125(a) table revised
25199
250.143(a) amended
25200
250.160(f) and (g) amended
25200
250.165(a) and (b) amended
25200
250.169(a) amended
25200
250.175(b)(3) amended
25200
250.186(b)(2) amended
25200
250.194(c) amended
25200
250.197(a)(8) and (b)(7) amended
25200
250.198(e) table amended
8902
(e) table revised
12092
(d) table revised
25200
250.199(b) and (e) table amended
25200
250.201(a)(3) amended
25200
250.210(a) and (b) amended
25200
250.216(a) revised
18584
250.221(b) redesignated as (c); new (b) added
18584
250.223Revised
18585
250.227(a)(3) and (c)(1) revised
18585
250.232(a)(2) amended
25200
250.247(a) revised
18585
250.252(b) redesignated as (c); new (b) added
18585
250.254Revised
18585
250.261(a)(3) and (c)(1) revised
18585
250.270(a)(1)(i) revised
18585
(a)(1)(i) amended
25200
250.281(a)(3) amended
25200
250.282Introductory text revised
18585
250.285(c) amended
25201
250.408Amended
25201
250.410(d)(2) amended
25201
250.415(e) added
8903
250.417(c)(1) amended
25201
250.466Introductory text amended
25201
250.490(p)(2) revised
12096
(o)(3) amended
25201
250.513(a), (c) and (d) revised
25201
250.613(d) amended
25201
250.801(e)(4) revised
12096
(h)(1) amended
25201
250.802(d) amended
12096
(e)(3) and (4)(i) amended
25201
250.803(b)(1) amended
12096
250.806(a)(2)(ii) revised
12096
250.901(a)(3) revised
12096
250.1001Amended
25201
250.1002(a) and (b)(2) amended
12096
(c)(2) amended
25201
250.1003(b)(1) amended
25201
250.1004(b)(2) amended
25201
250.1005(b) amended
25201
250.1007(a)(4) amended
25201
250.1010(c) and (h) amended
25201
250.1011(b)(1) revised; (b)(2) amended
25201
250.1016(c)(1) amended
25201
250.1019Amended
25201
250.1102(a)(1) amended
25201
250.1103(a) amended
25201
250.1202(f)(1) amended
25201
250.1403Revised
8899
250.1602(b) amended
25201
250.1619(b) amended
25201
250.1629(b)(1) introductory text amended
12096
251.7(b) introductory text revised; (b)(6) amended
25201
251.14(b) introductory text amended
25202
253Authority citation revised
8899
253.51(a) revised
8899
260.102Amended
25202
2008
(Regulations published from January 1, 2008 through July 1, 2008)
30 CFR
73 FR
Page
Chapter II
203.41(b) introductory text and (d) introductory text revised
15889
203.44(b) introductory text revised
15890
206.51Amended
15890
206.56(b)(1), (2) and (d) revised
15890
206.57(c)(4) and (e)(1) revised
15890
206.116Revised
15890
206.151Amended
15890
206.156(c) and (d) revised
15890
206.157(a)(1)(i) and (b)(1) amended; (d)(1) removed; (d)(2), (3) and (4) redesignated as new (d)(1), (2) and (3)
15891
206.158(e) revised
15891
206.159(a)(1)(i), (b)(1), (c)(1)(i), (2)(i), (d) heading and (e)(1) amended; (d)(1) removed; (d)(2), (3) and (4) redesignated as new (d)(1), (2) and (3)
15891
206.171Amended
15891
206.177(c)(1) and (2) amended
15891
206.178(d)(2) amended
15891
206.180(c)(2) amended
15891
206.251Amended
15891
206.252Revised
15891
206.254Amended
15891
206.259(d)(1) amended
15891
206.262(d)(1) amended
15891
206.451Amended
15891
206.453Amended
15892
210.01—210.40 (Subpart A)Revised
15892
210.50—210.60 (Subpart B)Revised
15892
210.100—210.106 (Subpart C)Added
15892
210.150—210.158 (Subpart D)Added
15892
210.200—210.206 (Subpart E)Heading revised
15897
210.205Redesignated as 210.206; new 210.205 added
15897
210.206Redesignated as 210.207; new 210.206 redesignated from 210.205
15897
210.207Redesignated from 210.206
15897
216Removed
15897
218Heading revised
15897
218.40(a), (b) and (c) revised
15897
218.41(a) through (e) revised
15897
218.50(b) revised
15898
218.51(a) amended; (f)(1) and (2) revised
15898
218.52(a) introductory text, (1), (4)(i) and (c) introductory text revised
15898
218.57Removed
15898
218.154(c) amended
15898
218.155(b)(2) amended
15898
227.401(f) revised
15898
250Authority citation revised
20168, 20171
250.107(a)(2) amended
20171
250.198(e) table amended
20168
250.260(a) amended
20171
250.803(b)(8) and (9)(i) amended
20171
250.806(c) amended
20171
250.900(a) amended
20171
250.901(a)(4) through (20) redesignated as (a)(7) through (23); new (a)(4), (5) and (6) added; new (a)(7), (23) and (d) revised
20169
250.1201Amended
20171
250.1202(k)(3) and (4) amended
20171
250.1204(b)(1) amended
20171
250.1301(b) and (c) revised
20172
250.1502Removed
20172
250.1629(b)(1) introductory text and (i) amended
20172
270Authority citation revised
20172
270.6Amended
20172
281Authority citation revised
20172
281.0Amended
20172
281.26(e) amended; (i) revised
20172
282Authority citation revised
20172
282.40(f) revised
20172
291Added; eff. 8-18-08
34640
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