[Title 30 CFR ]
[Code of Federal Regulations (annual edition) - July 1, 2000 Edition]
[From the U.S. Government Printing Office]



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                    30


          Parts 200 to 699

                         Revised as of July 1, 2000

Mineral Resources





          Containing a Codification of documents of general 
          applicability and future effect
          As of July 1, 2000
          With Ancillaries
          Published by
          Office of the Federal Register
          National Archives and Records
          Administration

As a Special Edition of the Federal Register



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                     U.S. GOVERNMENT PRINTING OFFICE
                            WASHINGTON : 2000



               For sale by U.S. Government Printing Office
 Superintendent of Documents, Mail Stop: SSOP, Washington, DC 20402-9328



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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                      551
          Chapter IV--Geological Survey, Department of the 
          Interior                                                 555
          Chapter VI--Bureau of Mines, Department of the 
          Interior                                                 567
  Finding Aids:
      Material Approved for Incorporation by Reference........     581
      Table of CFR Titles and Chapters........................     591
      Alphabetical List of Agencies Appearing in the CFR......     609
      Redesignation Table.....................................     619
      List of CFR Sections Affected...........................     623



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                     ----------------------------

                     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.

                     ----------------------------

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                               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.

LEGAL STATUS

    The contents of the Federal Register are required to be judicially 
noticed (44 U.S.C. 1507). The Code of Federal Regulations is prima facie 
evidence of the text of the original documents (44 U.S.C. 1510).

HOW TO USE THE CODE OF FEDERAL REGULATIONS

    The Code of Federal Regulations is kept up to date by the individual 
issues of the Federal Register. These two publications must be used 
together to determine the latest version of any given rule.
    To determine whether a Code volume has been amended since its 
revision date (in this case, July 1, 2000), consult the ``List of CFR 
Sections Affected (LSA),'' which is issued monthly, and the ``Cumulative 
List of Parts Affected,'' which appears in the Reader Aids section of 
the daily Federal Register. These two lists will identify the Federal 
Register page number of the latest amendment of any given rule.

EFFECTIVE AND EXPIRATION DATES

    Each volume of the Code contains amendments published in the Federal 
Register since the last revision of that volume of the Code. Source 
citations for the regulations are referred to by volume number and page 
number of the Federal Register and date of publication. Publication 
dates and effective dates are usually not the same and care must be 
exercised by the user in determining the actual effective date. In 
instances where the effective date is beyond the cut-off date for the 
Code a note has been inserted to reflect the future effective date. In 
those instances where a regulation published in the Federal Register 
states a date certain for expiration, an appropriate note will be 
inserted following the text.

OMB CONTROL NUMBERS

    The Paperwork Reduction Act of 1980 (Pub. L. 96-511) requires 
Federal agencies to display an OMB control number with their information 
collection request.

[[Page vi]]

Many agencies have begun publishing numerous OMB control numbers as 
amendments to existing regulations in the CFR. These OMB numbers are 
placed as close as possible to the applicable recordkeeping or reporting 
requirements.

OBSOLETE PROVISIONS

    Provisions that become obsolete before the revision date stated on 
the cover of each volume are not carried. Code users may find the text 
of provisions in effect on a given date in the past by using the 
appropriate numerical list of sections affected. For the period before 
January 1, 1986, consult either the List of CFR Sections Affected, 1949-
1963, 1964-1972, or 1973-1985, published in seven separate volumes. For 
the period beginning January 1, 1986, a ``List of CFR Sections 
Affected'' is published at the end of each CFR volume.

INCORPORATION BY REFERENCE

    What is incorporation by reference? Incorporation by reference was 
established by statute and allows Federal agencies to meet the 
requirement to publish regulations in the Federal Register by referring 
to materials already published elsewhere. For an incorporation to be 
valid, the Director of the Federal Register must approve it. The legal 
effect of incorporation by reference is that the material is treated as 
if it were published in full in the Federal Register (5 U.S.C. 552(a)). 
This material, like any other properly issued regulation, has the force 
of law.
    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.
    What if the material incorporated by reference cannot be found? If 
you have any problem locating or obtaining a copy of material listed in 
the Finding Aids of this volume as an approved incorporation by 
reference, please contact the agency that issued the regulation 
containing that incorporation. If, after contacting the agency, you find 
the material is not available, please notify the Director of the Federal 
Register, National Archives and Records Administration, Washington DC 
20408, or call (202) 523-4534.

CFR INDEXES AND TABULAR GUIDES

    A subject index to the Code of Federal Regulations is contained in a 
separate volume, revised annually as of January 1, entitled CFR Index 
and Finding Aids. This volume contains the Parallel Table of Statutory 
Authorities and Agency Rules (Table I). A list of CFR titles, chapters, 
and parts and an alphabetical list of agencies publishing in the CFR are 
also included in this volume.
    An index to the text of ``Title 3--The President'' is carried within 
that volume.
    The Federal Register Index is issued monthly in cumulative form. 
This index is based on a consolidation of the ``Contents'' entries in 
the daily Federal Register.
    A List of CFR Sections Affected (LSA) is published monthly, keyed to 
the revision dates of the 50 CFR titles.

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REPUBLICATION OF MATERIAL

    There are no restrictions on the republication of material appearing 
in the Code of Federal Regulations.

INQUIRIES

    For a legal interpretation or explanation of any regulation in this 
volume, contact the issuing agency. The issuing agency's name appears at 
the top of odd-numbered pages.
    For inquiries concerning CFR reference assistance, call 202-523-5227 
or write to the Director, Office of the Federal Register, National 
Archives and Records Administration, Washington, DC 20408 or e-mail 
[email protected].

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site also contains links to GPO Access.

                              Raymond A. Mosley,
                                    Director,
                          Office of the Federal Register.

July 1, 2000.



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                               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, 2000.

    Redesignation tables appear in the first and second volumes of title 
30.

    For this volume, Ruth Reedy Green was Chief Editor. The Code of 
Federal Regulations publication program is under the direction of 
Frances D. McDonald, assisted by Alomha S. Morris.

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

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                       TITLE 30--MINERAL RESOURCES




                  (This book contains parts 200 to 699)

  --------------------------------------------------------------------



  Editorial Note: Other regulations issued by the Department of the 
Interior appear in title 25, chapters I and II; title 36, chapter I; 
title 41, chapter 114; title 43; and title 50, chapters I and IV.
                                                                    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 vi--Bureau of Mines, Department of the Interior.....         515

Cross References: Bureau of Land Management, Department of the Interior, 
  regulations with respect to mineral lands: 43 CFR, chapter II, 
  subchapter C.

  Foreign Trade Statistics, Bureau of the Census, Department of 
Commerce: 15 CFR part 30.

  Forest Service regulations relating to mineral developments and mining 
in national forests: 36 CFR part 228.

  General Services Administration regulations for stockpiling of 
strategic and critical materials: 41 CFR chapter 101, subchapter C.

  Interstate Commerce Commission: 49 CFR chapter X.

  Bureau of Indian Affairs, Department of the Interior, energy and 
minerals regulations: 25 CFR chapter I, subchapter I.

[[Page 3]]



                CHAPTER II--MINERALS MANAGEMENT SERVICE,






                       DEPARTMENT OF THE INTERIOR




                           (Parts 200 to 699)

  --------------------------------------------------------------------

                    SUBCHAPTER A--ROYALTY MANAGEMENT
Part                                                                Page
201             General.....................................           5
202             Royalties...................................           5
203             Relief or reduction in royalty rates........          13
206             Product valuation...........................          31
207             Sales agreements or contracts governing the 
                    disposal of lease products..............         143
208             Sale of Federal royalty oil.................         144
210             Forms and reports...........................         152
212             Records and files maintenance...............         162
215

Accounting and auditing standards [Reserved]

216             Production accounting.......................         164
217             Audits and inspections......................         172
218             Collection of royalties, rentals, bonuses 
                    and other monies due the Federal 
                    Government..............................         173
219             Distribution and disbursement of royalties, 
                    rentals, and bonuses....................         187
220             Accounting procedures for determining net 
                    profit share payment for outer 
                    Continental Shelf oil and gas leases....         188
227             Delegation to States........................         201
228             Cooperative activities with States and 
                    Indian tribes...........................         213
229             Delegation to States........................         217
230             Recoupments and refunds.....................         224
232

Interest payments [Reserved]

233

Escrow and investments [Reserved]

234

Bonding--payment liability [Reserved]

241             Penalties...................................         230
242

Orders [Reserved]

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243             Suspensions pending appeal and bonding--
                    Royalty Management Program..............         235
                         SUBCHAPTER B--OFFSHORE
250             Oil and gas and sulphur operations in the 
                    Outer Continental Shelf.................         241
251             Geological and geophysical (G & G) 
                    explorations of the Outer Continental 
                    Shelf...................................         422
252             Outer Continental Shelf (OCS) oil and gas 
                    information program.....................         435
253             Oil spill financial responsibility for 
                    offshore facilities.....................         440
254             Oil-spill response requirements for 
                    facilities located seaward of the coast 
                    line....................................         454
256             Leasing of sulphur or oil and gas in the 
                    Outer Continental Shelf.................         466
259             Mineral leasing: Definitions................         494
260             Outer Continental Shelf oil and gas leasing.         494
270             Nondiscrimination in the Outer Continental 
                    Shelf...................................         501
280             Prospecting for minerals other than oil, 
                    gas, and sulfur in the outer continental 
                    shelf...................................         502
281             Leasing of minerals other than oil, gas, and 
                    sulphur in the outer continental shelf..         509
282             Operations in the outer continental shelf 
                    for minerals other than oil, gas, and 
                    sulphur.................................         522
                          SUBCHAPTER C--APPEALS
290             Appeals procedures..........................         545

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                    SUBCHAPTER A--ROYALTY MANAGEMENT





PART 201--GENERAL--Table of Contents




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 Royalty 
          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. Sec. 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



Sec. 201.100  Responsibilities of the Associate Director for Royalty 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]



PART 202--ROYALTIES--Table of Contents




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.

[[Page 6]]

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.

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.



Sec. 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]



Sec. 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).



Sec. 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



Sec. 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

[[Page 7]]

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]



Sec. 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  deg.F.

[[Page 8]]

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  deg.F.

[53 FR 1217, Jan. 15, 1988]



                         Subpart D--Federal Gas

    Source: 53 FR 1271, Jan. 15, 1988, unless otherwise noted.



Sec. 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

[[Page 9]]

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]



Sec. 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]



Sec. 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  deg.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

[[Page 10]]

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  deg.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



Sec. 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.



Sec. 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.



Sec. 202.351  Royalties on geothermal resources.

    (a) Royalties on geothermal resources, including byproduct minerals 
and commercially demineralized water, shall 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 shall be paid in 
value. The royalty due shall be the value determined pursuant to subpart 
H of 30 CFR part 206 multiplied by the royalty rate in the lease.
    (b)(1) Royalties are due on all geothermal resources, except those 
specified in paragraph (b)(2) of this section, that are produced from a 
lease and are sold or utilized by the lessee or are reasonably 
susceptible to sale or utilization by the lessee.
    (2) Geothermal resources that are unavoidably lost, as determined by 
the Bureau of Land Management (BLM), and geothermal resources that are 
reinjected prior to use on or off the lease, as approved by BLM, are not 
subject to royalty. The Minerals Management Service (MMS) will allow 
free of royalty a reasonable amount of geothermal energy necessary to 
generate electricity for internal powerplant operations or to generate 
electricity returned to the lease for lease operations. If a powerplant 
uses geothermal production from more than one lease, or uses unitized or 
communitized production, only that proportionate share of each lease's 
production (actual or allocated) necessary to operate the powerplant may 
be used royalty free. The MMS will also allow free of royalty a 
reasonable amount of commercially demineralized water necessary for 
powerplant operations or otherwise used on or for the benefit of the 
lease.
    (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 is due, the value of those geothermal 
resources shall be determined in accordance with subpart H of 30 CFR 
part 206.
    (d) If a lessee receives insurance or other compensation for 
unavoidably lost geothermal resources (including byproducts), royalties 
at the rates specified in the lease are due on the

[[Page 11]]

amount of that compensation. This paragraph shall not apply to 
compensation through self-insurance.



Sec. 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.



Sec. 202.353  Measurement standards for reporting and paying royalties.

    (a) For geothermal resources used to generate electricity, the 
quantity on which royalty is due shall be reported on Form MMS-2014 
(Report of Sales and Royalty Remittance) as follows:
    (1) For geothermal resources valued under arm's-length or non-arm's-
length contracts, quantities shall be reported in:
    (i) Kilowatthours to the nearest whole kilowatthour if the contract 
specifies payment in terms of generated electricity,
    (ii) Thousands of pounds to the nearest whole thousand pounds if the 
contract specifies payment in terms of weight, or
    (iii) Millions of Btu's to the nearest whole million Btu if the 
contract specifies payment in terms of heat or thermal energy.
    (2) For geothermal resources valued by the netback procedure 
pursuant to 30 CFR 206.352(c)(1)(ii) or (d)(1)(ii), the quantities shall 
be reported in kilowatthours to the nearest whole kilowatthour.
    (b) For geothermal resources used in direct utilization processes, 
the quantity on which royalty is due shall be reported on Form MMS-2014 
in:
    (1) Millions of Btu's to the nearest whole million Btu if valuation 
is in terms of thermal energy used or displaced,
    (2) Hundreds of gallons to the nearest hundred gallons of geothermal 
fluid produced if valuation is in terms of volume, or
    (3) Other measurement unit approved by MMS for valuation and 
reporting purposes.
    (c) For byproduct minerals, the quantity on which royalty is due 
shall be reported on Form MMS-2014 consistent with MMS-established 
reporting standards.
    (d) For commercially demineralized water, the quantity on which 
royalty is due shall be reported on Form MMS-2014 in hundreds of gallons 
to the nearest hundred gallons.
    (e) Lessees are not required to report the quality of geothermal 
resources, including byproducts, to MMS. The lessee must maintain 
quality measurements for audit and valuation purposes. Quality 
measurements include, but are not limited to, temperatures and chemical 
analyses for fluid geothermal resources and chemical analyses, weight 
percent, or other purity measurements for byproducts.

Subpart I--OCS Sulfur--[Reserved]



              Subpart J-- Gas Production From Indian Leases

    Source: 64 FR 43514, Aug. 10, 1999, unless otherwise noted.



Sec. 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.

[[Page 12]]

    (e) Reporting and paying. You must report and pay royalties as 
provided in part 218 of this title.



Sec. 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 Secs. 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.



Sec. 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 Sec. 202.553 
for information on how to value this production. If you take less than 
your entitled share of production, see Sec. 202.554 for information on 
how to value production you are entitled to but do not take.



Sec. 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.



Sec. 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 Sec. 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 Sec. 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 
Sec. 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.

[[Page 13]]

    (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.



Sec. 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.



Sec. 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.



Sec. 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.



Sec. 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).



PART 203--RELIEF OR REDUCTION IN ROYALTY RATES--Table of Contents




                      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  When can I get royalty relief?
203.3  Why must I pay a fee to request royalty relief?

[[Page 14]]

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

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

                  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?
203.65  How long will MMS take to evaluate my application?
203.66  What happens if MMS does not act in the time allowed under 
          Sec. 203.65, including any extensions?
203.67  What economic criteria must I meet to get royalty relief on an 
          authorized field or expansion 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?

                            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.



Sec. 203.0  What definitions apply to this part?

    Authorized field means a field in a water depth of at least 200 
meters and

[[Page 15]]

in the Gulf of Mexico west of 87 degrees, 30 minutes West longitude from 
which no current pre-Act lease produced, other than test production, 
before November 28, 1995.
    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.
    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.
    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 results from a lease sale held 
after November 28, 1995; is located in the Gulf of Mexico (GOM) in water 
depths 200 meters or deeper; lies wholly west of 87 degrees, 30 minutes 
West longitude; and is offered subject to a royalty-suspension volume 
authorized by statute.
    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 increase 
the ultimate recovery of resources from a pre-Act lease and that 
involves a substantial capital investment (e.g., fixed-leg platform, 
subsea template and manifold, tension-leg platform, multiple well 
project, etc.).
    Fabrication (or start of construction) means evidence of 
irreversible commitment to a concept and scale of development, including 
copies of a binding contract between you (as applicant) and a 
fabrication yard, a letter from a fabricator certifying that 
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 production 
resulting from lease-development activities involving a substantial 
capital investment (e.g., fixed-leg platform, subsea template and 
manifold, tension-leg platform, multiple well project, etc.) on a 
current pre-Act lease under a Development Operations Coordination 
Document--or its 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.
    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 issued as a result of a lease sale held 
before November 28, 1995; in a water depth of at least 200 meters; and 
in the Gulf of Mexico 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.
    Redetermination means your request for us to reconsider our 
determination on royalty relief if we have rejected your application or 
if we have granted relief but you want a larger suspension volume.
    Renounce means action you take to give up relief after we have 
granted it and before you start production.

[[Page 16]]

    Sunk costs means costs (as specified in 30 CFR 203.89(a)) of 
exploration, development, and production that you incur after the date 
of first discovery on the field and before the date we receive your 
complete application for royalty relief. Sunk costs include the costs of 
the discovery well qualified as producible under 30 CFR part 250, 
subpart A but do not include any pre-discovery activity costs or lease 
acquisition and holding costs such as cash bonus and rental payments.
    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.



Sec. 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.



Sec. 203.2  When can I get royalty relief?

    We can reduce or suspend royalties for OCS leases or projects that 
meet the criteria in the following table.

------------------------------------------------------------------------
                                                       THEN YOU MAY BE
    IF YOU HAVE A LEASE--         AND IF YOU--            GRANTED--
------------------------------------------------------------------------
That generates earnings       Seek to increase      A reduced royalty
 which cannot sustain          production by         rate on current
 production (End-of-Life       operating the lease   production flows
 lease),.                      beyond the point at   along with a higher
                               which it is           royalty rate on
                               economic under the    some additional
                               existing royalty      production flows.
                               rate,.
In designated areas of the    Are producing and     A royalty suspension
 deep water GOM, acquired in   seek to increase      for an increment to
 a lease sale held before      ultimate recovery     production large
 November 28, 1995, and you    of resources from     enough to make the
 propose activity in a DOCD    the field with a      project economic.
 or supplement to              substantial
 significantly expand          investment (e.g.,
 production,.                  platform, multiple
                               wells, subsea
                               template) (an
                               expansion project),.
In designated areas of the    Are on a field from   A royalty suspension
 deep water GOM, acquired in   which no current      for a minimum
 a lease sale held before      pre-Act lease         production volume
 November 28, 1995 (pre-Act    produced (other       plus any additional
 lease),.                      than test             volume needed to
                               production) before    make the field
                               November 28, 1995     economic.
                               (authorized field),.
------------------------------------------------------------------------



Sec. 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

[[Page 17]]

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.



Sec. 203.4  How do the provisions in this part apply to different types of leases and projects?

    The tables in this section summarize how similar provisions in this 
part apply in different situations.
    (a) Provisions relating to application content in Secs. 203.51, 
203.62 and 203.81 through 203.89.

----------------------------------------------------------------------------------------------------------------
                                                                                   Deep water
                     Information elements                        End-of-life       expansion       Pre-act deep
                                                                    lease           project        water lease
----------------------------------------------------------------------------------------------------------------
Administrative information report............................               x                x                x
Net revenue and relief justification report (prescribed                     x
 format).....................................................
Economic viability and relief justification report (Royalty    ...............               x                x
 Suspension Viability Program (RSVP) model inputs justified
 with Geological & Geophysical (G&G), Engineering,
 Production, & Cost reports).................................
G&G report...................................................  ...............               x                x
Engineering report...........................................  ...............               x                x
Production report............................................  ...............               x                x
Deep Water cost report.......................................  ...............               x                x
----------------------------------------------------------------------------------------------------------------

    (b) Provisions relating to verification in Secs. 203.70, 203.81 and 
203.90 through 203.91.

----------------------------------------------------------------------------------------------------------------
                                                                                   Deep water
                    Confirmation elements                        End-of-life       expansion       Pre-act deep
                                                                    lease           project        water lease
----------------------------------------------------------------------------------------------------------------
Fabricator's confirmation report.............................  ...............               x                x
Post-production development report (approved by certified      ...............               x                x
 public accountant (CPA).....................................
----------------------------------------------------------------------------------------------------------------

    (c) Provisions relating to approval criteria contained in 
Secs. 203.50, 203.52, 203.60 and 203.67.

----------------------------------------------------------------------------------------------------------------
                                                                                   Deep water
                     Approval conditions                         End-of-life       expansion       Pre-act deep
                                                                    lease           project        water lease
----------------------------------------------------------------------------------------------------------------
At least 12 of the last 15 months have the required level of                x
 production..................................................
Already producing............................................               x                x
Well can produce.............................................  ...............  ...............               x
Royalties for qualifying months exceed 75 percent of net                    x
 revenue (NR)................................................
Substantial investment (e.g., platform, multiple wells,        ...............               x
 subsea template)............................................
Determined to be economic only with relief...................  ...............               x                x
----------------------------------------------------------------------------------------------------------------

    (d) Provisions related to redetermination in Secs. 203.52 and 203.74 
through 203.75.

----------------------------------------------------------------------------------------------------------------
                                                                                   Deep water
                  Redetermination conditions                     End-of-life       expansion       Pre-act deep
                                                                    lease           project        water lease
----------------------------------------------------------------------------------------------------------------
After 12 months under current rate, criteria same as for                    x
 approval....................................................
For material change in geologic data, prices, or costs.......  ...............               x                x
----------------------------------------------------------------------------------------------------------------


[[Page 18]]

    (e) Provisions related to the format of relief in Secs. 203.53 and 
203.69.

----------------------------------------------------------------------------------------------------------------
                                                                                   Deep water
                     Relief rate & volume                        End-of-life       expansion       Pre-act deep
                                                                    lease           project        water lease
----------------------------------------------------------------------------------------------------------------
One-half pre-application effective lease rate on the                        x
 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..............................................
Qualifying amount is the average monthly production for 12                  x
 qualifying months...........................................
Zero royalty rate on the suspension volume and the original                                  x                x
 lease rate on additional production.........................
Field Suspension volume is at least 17.5, 52.5 or 87.5                                                        x
 million barrels of oil equivalent (MMBOE)...................
Amount needed to become economic.............................                                x                x
----------------------------------------------------------------------------------------------------------------

    (f) Provisions related to discontinuing relief Secs. 203.54 and 
203.78.

----------------------------------------------------------------------------------------------------------------
                                                                                   Deep water
                 Full royalty resumes when--                     End-of-life       expansion       Pre-act deep
                                                                    lease           project        water lease
----------------------------------------------------------------------------------------------------------------
Average NYMEX price for last 12 months is at least 25 percent               x
 above the average for the qualifying months.................
Average NYMEX price for last 12 months exceeds $28/bbl or                                    x                x
 $3.50/mcf, escalated by the gross domestic product deflator
 since 1994..................................................
----------------------------------------------------------------------------------------------------------------

    (g) Provisions related to the end, loss or reduction of relief in 
Secs. 203.55 and 203.76.

----------------------------------------------------------------------------------------------------------------
                                                                                   Deep water
                 Relief withdrawn or reduced                     End-of-life       expansion       Pre-act deep
                                                                    lease           project        water lease
----------------------------------------------------------------------------------------------------------------
Recipient so requests........................................               x
Lease rate is at the effective rate for 12 consecutive months               x
Conditions that we may specify in the approval letter in                    x
 individual cases actually occur.............................
Not submitting post-production report that compares expected                                 x                x
 to actual costs.............................................
Change of development system.................................                                x                x
Excess delay in starting fabrication.........................                                x                x
Spending less than 80 percent of proposed pre-production                                     x                x
 costs but notifying us in post-production report............
Amount of relief volume is produced..........................                                x                x
----------------------------------------------------------------------------------------------------------------



               Subpart B-OCS Oil, Gas, and Sulfur General

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

                  Royalty Relief for End-of-life Leases



Sec. 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 Sec. 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 Sec. 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.,

[[Page 19]]

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]



Sec. 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 Sec. 203.83) 
and
    (b) A net revenue and relief justification report (specified in 
Sec. 203.84).



Sec. 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 Sec. 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.



Sec. 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 
Sec. 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.



Sec. 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.



Sec. 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

[[Page 20]]

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.



Sec. 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



Sec. 203.60  Who may apply for deep water royalty relief?

    Under conditions in Secs. 203.61(b) and 203.62, you may apply for 
royalty relief 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 lease to a field (as defined in 
Sec. 203.0); and
    (c) You hold a pre-Act lease on an authorized field (as defined in 
Sec. 203.0) or you propose an expansion project (as defined in 
Sec. 203.0).



Sec. 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 Sec. 203.3.
    (b) You must wait at least 90 days after receiving our assessment to 
apply for relief under Sec. 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, Sec. 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.



Sec. 203.62  How do I apply for relief?

    You must send a complete application and the required fee to the MMS 
GOM Regional Director.
    (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 GOM Regional Office will guide you 
on the format for the required reports.



Sec. 203.63  Does my application have to include all leases in the field?

    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 (c) of this section and 
Sec. 203.64.
    (a) The Regional Director maintains a Field Names Master List with 
updates of all leases in each designated field.
    (b) 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

[[Page 21]]

the field. We will not disclose proprietary data when explaining our 
assumptions and reasons for our determinations under Sec. 203.67.
    (c) 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.



Sec. 203.64  How many applications may I file on a field?

    You may file one complete application for royalty relief during the 
life of the field. However, you may send another application if:
    (a) You are eligible to apply for a redetermination under 
Sec. 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.



Sec. 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 and a redetermination under Sec. 203.75 within 120 days after we 
say 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   Ask to extend the 120-day or 180-
 costs.                               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  Add another 30 days. We may add
 for a valid reason, such as          more than 30 days, but only if you
 missing vital information or         agree.
 inconsistent or inconclusive
 supporting data.
We need more data, explanations, or  Ask to extend the 120-day or 180-
 revision.                            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 Sec. 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.



Sec. 203.66  What happens if MMS does not act in the time allowed under Sec. 203.65, including any extensions?

    If we do not act within the timeframes established in Sec. 203.65, 
the conditions in the following table apply.

------------------------------------------------------------------------
                                 And we do not decide
   If you apply for royalty         within the time     As long as you--
         relief for--                 specified--
------------------------------------------------------------------------
An authorized field...........  You get the minimum     Abide by Secs.
                                 suspension volumes      203.70 & 76
                                 specified in Sec.
                                 203.69.
An expansion project..........  You get a royalty       Abide by Secs.
                                 suspension for the      203.70 & 76
                                 first year of
                                 production.
------------------------------------------------------------------------



Sec. 203.67  What economic criteria must I meet to get royalty relief on an authorized field or expansion project?

    Your field or project must require royalty relief to be economic and 
must become economic with this relief. That is, we will not approve 
applications if we determine that royalty relief cannot make the field 
or project economically viable.

[[Page 22]]



Sec. 203.68  What pre-application costs will MMS consider in determining economic viability?

    (a) We will not consider ineligible costs as set forth in 
Sec. 203.89(h) in determining economic viability for purposes of royalty 
relief.
    (b) We will consider sunk costs (allowable expenditures on and after 
the discovery well as specified in Sec. 203.89(a)) in accordance with 
the following table.

------------------------------------------------------------------------
          We will--                              When--
------------------------------------------------------------------------
Include sunk costs...........  The field has not produced, other than
                                test production, before the application
                                submission date.
Not include sunk costs.......  Determining whether an authorized field
                                can become economic with any relief (see
                                Sec.  203.67).
Not include sunk costs.......  Determining how much suspension volume is
                                necessary to make development economic
                                (see Sec.  203.69(c)).
Not include sunk costs.......  Evaluating an expansion project.
------------------------------------------------------------------------



Sec. 203.69  If my application is approved, what royalty relief will I receive?

    This section applies only to leases on which you have applied for 
and received a royalty-suspension volume under section 302 of the DWRRA. 
We will not collect royalties on a specified suspension volume for your 
field. Suspension amounts include volumes allocated to a lease under an 
approved unit agreement and exclude any volumes that do not bear a 
royalty under the lease or the regulations of this chapter.
    (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) If the application for the field includes leases in different 
categories of water depth, we apply the minimum royalty-suspension 
volume for the deepest lease then associated with the field. We base the 
water depth and makeup of a field on the water-depth delineations in the 
``Royalty Suspension Areas Map'' and the Field Names Master List and 
updates in effect at the time your application is approved. These 
publications are available from the GOM Regional Office.
    (c) You will get a royalty-suspension volume above the minimum if we 
determine that you need more to make developing the field economic.
    (d) For expansion projects, the minimum suspension volumes do not 
apply. If we determine that your expansion project may be economic only 
with relief, we will determine and grant you the royalty-suspension 
volume necessary to make the project economic.
    (e) A royalty-suspension volume will continue through the end of the 
month in which cumulative production reaches that volume. The cumulative 
production is from all the leases in the authorized field or expansion 
project that are entitled to share the royalty suspension volume.



Sec. 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 and 203.90 through 203.91 describe what these reports 
must include. MMS's GOM Regional Office will tell you the formats.

------------------------------------------------------------------------
       Required report           When due to MMS     Due date extensions
------------------------------------------------------------------------
Fabricator's confirmation     Within 1 year after   MMS Director may
 report.                       approval of relief.   grant you an
                                                     extension under
                                                     Sec.  203.79(c) for
                                                     up to 1 year.
Post-production report......  Within 60 days after  With acceptable
                               the start of          justification from
                               production that is    you, MMS's GOM
                               subject to the        Regional Director
                               approved royalty-     may extend due date
                               suspension volume.    up to 60 days.
------------------------------------------------------------------------


[[Page 23]]



Sec. 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 the lease is 
assigned to the field, and whether we award the volume suspension by an 
approved application or establish it in the lease terms.
    (a) If your authorized field has an approved royalty-suspension 
volume under Secs. 203.67 and 203.69, we will suspend payment of 
royalties on production from all applying leases in the field until 
their cumulative production equals the approved volume. The following 
conditions also apply as appropriate:

------------------------------------------------------------------------
            If--                     Then--                 And--
------------------------------------------------------------------------
We assign an eligible lease   We will not change    The newly assigned
 to your field after we        your field's          leases may share in
 approve or establish relief.  royalty-suspension    any remaining
                               volume.               royalty relief.
We assign a pre-Act lease to  We will not change    The newly assigned
 your field after you submit   your field's          leases may share in
 a complete application.       royalty-suspension    any remaining
                               volume.               royalty relief by
                                                     filing the short
                                                     form application
                                                     specified in Sec.
                                                     203.83 and
                                                     authorized in Sec.
                                                     203.82.
We assigned a pre-Act lease   We will not change    The newly assigned
 to your field before you      your field's          lease will not
 submitted the royalty         royalty-suspension    share in the relief
 relief application.           volume.               if it did not
                                                     participate in the
                                                     application.
We reassign a well on a pre-  The past production   The past production
 Act lease to another field.   from that well        from that well will
                               counts toward the     not count toward
                               royalty suspension    any royalty
                               volume of the field   suspension volume
                               to which the well     granted to the
                               is reassigned.        field from which it
                                                     was reassigned.
------------------------------------------------------------------------

    (b) If your authorized field has an automatic royalty-suspension 
volume established under Sec. 260.110 of this chapter, we will suspend 
payment of royalties on production from all eligible leases in the field 
until their cumulative production equals the automatic volume. The 
following conditions also apply as appropriate:

------------------------------------------------------------------------
            If--                     Then--                 And--
------------------------------------------------------------------------
Another eligible lease is     Your field's royalty- The newly assigned
 assigned to your field.       suspension volume     lease may share in
                               does not change.      relief only to the
                                                     extent that
                                                     cumulative
                                                     production from
                                                     your field is less
                                                     than the automatic
                                                     volume.
A pre-Act lease applies       Your field's royalty- All leases in the
 (along with the other         suspension volume     field share the
 leases in the field) and      may increase or       one, higher royalty-
 qualifies (subject to the     stay the same.        suspension volume
 field's automatic                                   if we approve the
 suspension volume) for                              application;
 royalty relief under Secs.                             or
 203.67 and 203.69.                                 The eligible leases
                                                     in the field keep
                                                     the automatic
                                                     volume if we reject
                                                     the application.
------------------------------------------------------------------------

    (c) If you have an expansion project with more than one lease, the 
royalty-suspension volume for each lease equals that lease's actual 
incremental production from the project (or production allocated under 
an approved unit agreement) until cumulative incremental 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.



Sec. 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 Sec. 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 
Sec. 203.67.
    (b) An expansion project on your lease may receive a separate 
royalty-

[[Page 24]]

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 
Sec. 203.67.



Sec. 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.



Sec. 203.74  When will MMS reconsider its determination?

    Under certain conditions, you may request a redetermination if we 
deny your application, if you want your approved royalty-suspension 
volume to change, after we withdraw approval, or after you renounce 
royalty relief. To be eligible for a redetermination, at least one of 
the following three 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) Your current reference price decreases by more than 25 percent 
from your base reference price. For royalty relief on deep water 
expansion projects and pre-Act deep water leases:
    (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 oil and gas for the most recent full 12-calendar 
months preceding the date of your most recent, complete 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 Secs. 203.85 and 203.88) from your most 
recently approved application for this royalty relief.
    (c) 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 recent, complete application for 
this royalty relief.

[63 FR 2618, Jan. 16, 1998; 63 FR 24747, May 5, 1998]



Sec. 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 Sec. 203.62. We will evaluate 
your application under Sec. 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.



Sec. 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, tension leg platform to a moored catenary system such as a SPAR 
platform, an independent development and production system to one with 
subsea wells tied back to a host production facility, etc.).

[[Page 25]]

    (b) You do not start building the proposed development and 
production system within 1 year of the date we approved your 
application--unless the MMS Director grants you an extension under 
Sec. 203.79(c).
    (c) You do not tell us in your post-production development report 
(Sec. 203.70), and we find out your actual development costs are less 
than 80 percent of the eligible development costs estimated in your 
application's most likely scenario. Development costs are those incurred 
between the application submission date and start of production. If you 
tell us about this result in the post-production development report, you 
may retain 50 percent of the original royalty-suspension volume.
    (d) We granted you a royalty-suspension volume after you qualified 
for a redetermination under Sec. 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 Sec. 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 Sec. 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.



Sec. 203.77  May I voluntarily give up relief if conditions change?

    You may renounce approved royalty-suspension volumes as soon as you 
anticipate violating one of the withdrawal conditions, or for any other 
reason, before you start production.



Sec. 203.78  Do I keep relief if prices rise significantly?

    No, you must pay full royalties if prices rise above the statutory 
base price for light sweet crude oil or natural gas.
    (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 
Sec. 218.54 of this chapter) by April 30 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 Sec. 218.54 of this chapter) by April 30 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 during each calendar year after 1994. These prices 
change by the percentage the implicit price deflator for the gross 
domestic product changed during the preceding calendar year.

[[Page 26]]



Sec. 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 Sec. 203.67 and the royalty-suspension volumes under Sec. 203.69 
are final agency actions.
    (c) If you cannot start construction by the deadline in 
Sec. 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.

                            Required Reports



Sec. 203.81  What supplemental reports do royalty-relief applications require?

    (a) You must send us the supplemental reports listed below that 
apply to your field. Secs. 203.83 through 203.91 describe these reports 
in detail.

----------------------------------------------------------------------------------------------------------------
                                                                                   Deep water
                       Required reports                          End-of-life       expansion       Pre-act deep
                                                                    lease           project        water lease
----------------------------------------------------------------------------------------------------------------
Administrative information report............................               x                x                x
Net revenue & relief justification report....................               x   ...............  ...............
Economic viability & relief justification report (RSVP model   ...............               x                x
 inputs justified by other required reports).................
G&G report...................................................  ...............               x                x
Engineering report...........................................  ...............               x                x
Production report............................................  ...............               x                x
Deep water cost report.......................................  ...............               x                x
Fabricator's confirmation report.............................  ...............               x                x
Post-production development report...........................  ...............               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) You must submit with your application and post-production 
development report an additional report prepared by a 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 conforms to our most recent guidelines on royalty 
relief.
    (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.



Sec. 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:

[[Page 27]]

    (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 Sec. 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]



Sec. 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) Lessee's designation, the API number and location 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).



Sec. 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;

[[Page 28]]

    (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]



Sec. 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 
(Secs. 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.



Sec. 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

[[Page 29]]

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; and
    (7) Pressure-volume-temperature analysis, if available.
    (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) Identification of reservoirs not contemplated for development.
    (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; and
    (7) A yield distribution or point estimate (accompanied by 
explanations of why distributions less appropriately reflect the 
uncertainty) for each gas 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.



Sec. 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 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:

[[Page 30]]

    (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:
    (1) The conceptual basis for developing in phases and goals or 
milestones required for starting later phases; and
    (2) An explanation for excluding the reservoirs you are not planning 
to develop.
    (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 (Sec. 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.



Sec. 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.



Sec. 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 cost, which are all your eligible post-discovery 
exploration, development, and production expenses (no third party 
costs), and also include the eligible costs of the discovery well on the 
field. Report them in nominal dollars and only if you have 
documentation. We count sunk costs in an evaluation (specified in 
Sec. 203.68) as after-tax expenses, using nominal dollar amounts.
    (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

[[Page 31]]

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).



Sec. 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.



Sec. 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. Keep supporting records for 
these costs and make them available to us on request.

Subpart C--Federal and Indian Oil [Reserved]

Subpart D--Federal and Indian Gas [Reserved]

Subpart E--Solid Minerals, General [Reserved]



                             Subpart F--Coal



Sec. 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]



Sec. 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]



PART 206--PRODUCT VALUATION--Table of Contents




                      Subpart A--General Provisions

Sec.
206.10  Information collection.

                          Subpart B--Indian Oil

206.50  Purpose and scope.

[[Page 32]]

206.51  Definitions.
206.52  Valuation standards.
206.53  Point of royalty settlement.
206.54  Transportation allowances--general.
206.55  Determination of transportation allowances.

                         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 index price 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 under a non-
          arm's-length transportation arrangement?
206.112   What adjustments and transportation allowances apply when I 
          value oil using index pricing?
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 and assessments apply if I improperly report a 
          transportation allowance?
206.117   What reporting adjustments must I make for transportation 
          allowances?
206.118   Are actual or theoretical losses permitted as part of a 
          transportation allowance?
206.119   How are the royalty quantity and quality determined?
206.120   How are operating allowances determined?
206.121   Is there any grace period for reporting and paying royalties 
          after this subpart becomes effective?

                         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.

[[Page 33]]

206.261  Transportation allowances--general.
206.262  Determination of transportation allowances.
206.263  Contract submission.
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  Purpose and scope.
206.351  Definitions.
206.352  Valuation standards for electrical generation.
206.353  Determination of transmission deductions.
206.354  Determination of generating deductions.
206.355  Valuation standards for direct utilization.
206.356  Valuation standards for byproducts.
206.357  Byproduct transportation allowances--general.
206.358  Determination of byproduct transportation allowances.

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  Contract submission.
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.



                      Subpart A--General Provisions



Sec. 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.



Sec. 206.50  Purpose and scope.

    (a) This subpart is applicable to all oil production from Indian 
(Tribal and allotted) oil and gas leases (except leases on the Osage 
Indian Reservation, Osage County, Oklahoma). 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 specific provisions of any Federal statute, treaty, 
settlement agreement between the Indian lessor and a lessee resulting 
from administrative or judicial litigation, or oil and gas lease subject 
to the requirements of this subpart are inconsistent with any regulation 
in this subpart, then the statute, treaty, lease provision or settlement 
agreement shall govern to the extent of that inconsistency.
    (c) All royalty payments made to MMS or Indian Tribes are subject to 
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 oil and gas leases are discharged in accordance 
with the requirements of the governing mineral leasing laws, treaties, 
and lease terms.



Sec. 206.51  Definitions.

    For the purposes of this subpart:
    Allowance means an approved or an MMS-initially accepted deduction 
in determining value for royalty purposes. Transportation allowance 
means an allowance for the reasonable, actual

[[Page 34]]

costs incurred by the lessee for moving oil to a point of sale or point 
of delivery off the lease, unit area, or communitized area, excluding 
gathering, or an approved or MMS-initially accepted deduction for costs 
of such transportation, determined by this subpart.
    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 that has been 
arrived at in the market place 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.
    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.
    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 for 
onshore leases.
    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 oil 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 Indian lessor. Gross 
proceeds, as applied to oil, also includes, but is not limited to, 
reimbursements for harboring or terminaling fees. 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

[[Page 35]]

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 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 Indian leases.
    Lessee means any person to whom an 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 lease products means lease products which have similar 
chemical, physical, and legal characteristics.
    Load oil means any oil which has been used with respect to the 
operation of oil or gas wells for wellbore stimulation, workover, 
chemical treatment, or production purposes. It does not include oil used 
at the surface to place lease production in marketable condition.
    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.
    MMS means the Minerals Management Service of the Department of the 
Interior.
    Net-back method (or workback method) means a method for calculating 
market value of oil at the lease. Under this method, costs of 
transportation, processing, or manufacturing are deducted from the 
proceeds received for the oil and any extracted, processed, or 
manufactured products, or from the value of the oil or 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, to ascertain value at the lease.
    Net profit share (for applicable Indian lessees) means the specified 
share of the net profit from production of oil and gas as provided in 
the agreement.
    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. For purposes of royalty 
valuation, the term tar sands is defined separately from oil.
    Oil shale means a kerogen-bearing rock (i.e., fossilized, insoluble, 
organic material). Separation of kerogen from oil shale may take place 
in situ or in surface retorts by various processes. The kerogen, upon 
distillation, will yield liquid and gaseous hydrocarbons.
    Person means any individual, firm, corporation, association, 
partnership, consortium, or joint venture (when established as a 
separate entity).
    Posted price means the price specified in publicly available posted 
price bulletins, onshore terminal postings, or other price notices net 
of all adjustments for quality (e.g., API gravity, sulfur content, etc.) 
and location for oil in marketable condition.

[[Page 36]]

    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.
    Selling arrangement means the individual contractual arrangements 
under which sales or dispositions of oil are made. Selling arrangements 
are described by illustration in MMS Royalty Management Program Oil and 
Gas Payor Handbook.
    Spot sales agreement means a contract wherein a seller agrees to 
sell to a buyer a specified amount of oil 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.
    Tar sands means any consolidated or unconsolidated rock (other than 
coal, oil shale, or gilsonite) that contains a hydrocarbonaceous 
material with a gas-free viscosity greater than 10,000 centipoise at 
original reservoir temperature.

[61 FR 5455, Feb. 12, 1996, as amended at 64 FR 43288, Aug. 10, 1999]



Sec. 206.52  Valuation standards.

    (a)(1) The value of production, for royalty purposes, of oil from 
leases subject to this subpart shall be the value determined under this 
section less applicable allowances determined under this subpart.
    (2)(i) For any Indian leases which 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, shall be the higher of those 
two values.
    (ii) 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 
1 barrel of the oil (starting from the bottom) is sold.
    (b)(1)(i) The value of oil which is sold under an arm's-length 
contract shall be the gross proceeds accruing to the lessee, except as 
provided in paragraphs (b)(1)(ii) and (b)(1)(iii) 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, oil which is sold or otherwise transferred to the lessee's 
marketing affiliate and then sold by the marketing affiliate under an 
arm's-length contract shall be valued in accordance with this paragraph 
based upon the sale by the marketing affiliate.
    (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 oil. If the 
contract does not reflect the total consideration, then MMS may require 
that the oil 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 the lessee, including the additional consideration.
    (iii) If MMS determines that the gross proceeds accruing to the 
lessee under an arm's-length contract do not reflect the reasonable 
value of the production because of misconduct by or between two 
contracting parties, or because the lessee otherwise has breached its 
duty to the lessor to market the production for the mutual benefit of

[[Page 37]]

the lessee and the lessor, then MMS shall require that the oil 
production be valued under the first applicable of paragraph (c)(2), 
(c)(3), (c)(4), or (c)(5) 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. If the oil production is then valued under paragraph 
(c)(4) or (c)(5) of this section, the notification requirements of 
paragraph (e) of this section shall apply.
    (2) 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 oil.
    (c) The value of oil production from leases subject to this section 
which is not sold under an arm's-length contract shall be the reasonable 
value determined in accordance with the first applicable of the 
following paragraphs:
    (1) The lessee's contemporaneous posted prices or oil sales contract 
prices used in arm's-length transactions for purchases or sales of 
significant quantities of like-quality oil in the same field (or, if 
necessary to obtain a reasonable sample, from the same area); provided, 
however, that those posted prices or oil sales contract prices are 
comparable to other contemporaneous posted prices or oil sales contract 
prices used in arm's-length transactions for purchases or sales of 
significant quantities of like-quality oil in the same field (or, if 
necessary to obtain a reasonable sample, from the same area). In 
evaluating the comparability of posted prices or oil sales contract 
prices, the following factors shall be considered: Price, duration, 
market or markets served, terms, quality of oil, volume, and other 
factors as may be appropriate to reflect the value of the oil. If the 
lessee makes arm's-length purchases or sales at different postings or 
prices, then the volume-weighted average price for the purchases or 
sales for the production month will be used;
    (2) The arithmetic average of contemporaneous posted prices used in 
arm's-length transactions by persons other than the lessee for purchases 
or sales of significant quantities of like-quality oil in the same field 
(or, if necessary to obtain a reasonable sample, from the same area);
    (3) The arithmetic average of other contemporaneous arm's-length 
contract prices for purchases or sales of significant quantities of 
like-quality oil in the same area or nearby areas;
    (4) Prices received for arm's-length spot sales of significant 
quantities of like-quality oil from the same field (or, if necessary to 
obtain a reasonable sample, from the same area), and other relevant 
matters, including information submitted by the lessee concerning 
circumstances unique to a particular lease operation or the salability 
of certain types of oil;
    (5) A net-back method or any other reasonable method to determine 
value;
    (6) For purposes of this paragraph, the term lessee includes the 
lessee's designated purchasing agent, and the term contemporaneous means 
postings or contract prices in effect at the time the royalty obligation 
is incurred.
    (d) Any Indian lessee will make available, upon request to the 
authorized MMS or Indian 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 production sold, purchased, or otherwise obtained by the 
lessee from the field or area or from nearby fields or areas.
    (e)(1) Where the value is determined under 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) A lessee shall notify MMS if it has determined value under 
paragraph (c)(4) or (c)(5) of this section. The notification shall be by 
letter to MMS Associate Director for Royalty 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

[[Page 38]]

the month the lessee first reports royalties on a Form MMS-2014 using a 
valuation method authorized by paragraph (c)(4) or (c)(5) of this 
section and each time there is a change from one to the other of these 
two methods.
    (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 the difference computed under 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 value for royalty payment purposes until MMS issues a value 
determination. 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. 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 determined under this subpart.
    (i) The lessee is required to place oil in marketable condition at 
no cost to the Indian lessor unless otherwise provided in the lease 
agreement or this section. 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 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 oil in marketable condition.
    (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 oil.
    (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 Indian Tribes or 
allottees until the audit period is formally closed.
    (l) Certain information submitted to MMS to support valuation 
proposals, including transportation 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 laws 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 to which 
such lessor may be

[[Page 39]]

lawfully entitled from MMS or such lessor's lessee directly under the 
terms of the lease, 30 U.S.C. 1733, or other applicable law.



Sec. 206.53  Point of royalty settlement.

    (a)(1) Royalties shall be computed on the quantity and quality of 
oil as measured at the point of settlement approved by BLM for onshore 
leases.
    (2) If the value of oil determined under Sec. 206.52 of this subpart 
is based upon a quantity and/or quality different from the quantity and/
or quality at the point of royalty settlement approved by the BLM for 
onshore leases, the value shall be adjusted for those differences in 
quantity and/or quality.
    (b) No deductions may be made from the royalty volume or royalty 
value for actual or theoretical losses. Any actual loss that may be 
sustained prior to the royalty settlement metering or measurement point 
will not be subject to royalty provided that such actual loss is 
determined to have been unavoidable by BLM.
    (c) 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. There can be no 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 prior to 
or beyond the approved point of royalty settlement. Royalties are due on 
100 percent of the value of the oil as provided in this subpart. There 
can be no deduction from the value of the oil for royalty purposes to 
compensate for actual losses beyond the approved point of royalty 
settlement or for theoretical losses that are claimed to have taken 
place either prior to or beyond the approved point of royalty 
settlement.

[61 FR 5455, Feb. 12, 1996; 64 FR 43288, Aug. 10, 1999]



Sec. 206.54  Transportation allowances--general.

    (a) Where the value of oil has been determined under Section 206.52 
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 selling arrangement 
shall not exceed 50 percent of the value of the oil at the point of sale 
as determined under Sec. 206.52 of this subpart. Transportation costs 
cannot be transferred between selling arrangements 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) shall contain all relevant and 
supporting documentation necessary for MMS to make a determination. 
Under no circumstances shall the value, for royalty purposes, under any 
selling arrangement, be reduced to zero.
    (c) Transportation costs must be allocated among all products 
produced and transported as provided in Sec. 206.55. Transportation 
allowances for oil shall be expressed as dollars per barrel.
    (d) If, after a review and/or audit, MMS determines that a lessee 
has improperly determined a transportation allowance authorized by this 
subpart, then the lessee shall pay any additional royalties, plus 
interest determined in accordance with 30 CFR 218.54, or shall be 
entitled to a credit, without interest.



Sec. 206.55  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

[[Page 40]]

(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

[[Page 41]]

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

[[Page 42]]

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

[[Page 43]]

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.

[[Page 44]]

    (4) Transportation allowances must be reported as a separate line 
item 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 shall be required 
to 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 shall 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.



                         Subpart C--Federal Oil

    Source: 65 FR 14088, Mar. 15, 2000, unless otherwise noted.



Sec. 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

[[Page 45]]

will govern to the extent of the inconsistency.
    (e) MMS may audit and adjust all royalty payments.



Sec. 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 between 10 and 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

[[Page 46]]

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.
    Index pricing means using ANS crude oil spot prices, West Texas 
Intermediate (WTI) crude oil spot prices at Cushing, Oklahoma, or other 
appropriate crude oil spot prices for royalty valuation.
    Index pricing point means the physical location where an index price 
is established in an MMS-approved publication.
    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, other spot prices, or location 
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.
    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

[[Page 47]]

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).
    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.
    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 span of time during which crude oil trading 
occurs and spot prices are determined, generally for deliveries of 
production in the following calendar month. For example, for ANS spot 
prices, the trading month includes all business days in the calendar 
month. For other spot prices, for example, the trading month may include 
the span of time from the 26th of the previous month through the 25th of 
the current month.
    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.



Sec. 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 Secs. 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.

[[Page 48]]

    (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 Sec. 206.103 or at the total consideration received.
    (2) You must value the oil under Sec. 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 
Sec. 206.102(a) or Sec. 206.103 to value your production for royalty 
purposes.
    (i) If you use Sec. 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 Sec. 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 Sec. 206.102(d)(1) to use Sec. 206.102(a) 
or Sec. 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 Sec. 206.102(a) or 
Sec. 206.103 to value your production for royalty purposes.
    (ii) When you elect under Sec. 206.102(d)(2)(i) to use 
Sec. 206.102(a) or Sec. 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:

[[Page 49]]

    (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.



Sec. 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 
Sec. 206.102 or that you elect under Sec. 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 
Sec. 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.
    (1) If you have an MMS-approved tendering program, value your oil 
under paragraph (b)(2) of this section. If you do not have an MMS-
approved tendering program, you may value your oil under either 
paragraph (b)(3) or paragraph (b)(4) of this section.
    (i) You must apply the same subparagraph of this section to value 
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 you cannot value under Sec. 206.102 or that you elect under 
Sec. 206.102(d) to value under this section.
    (ii) After you select either paragraph (b)(3) or (b)(4) 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 one of the other paragraphs. If you change 
methods, you must begin a new 2-year period.
    (2) If you have an MMS-approved tendering program, the value of 
production from leases in the area the tendering program covers is the 
highest winning bid price for tendered volumes.
    (i) You must offer and sell at least 30 percent of your production 
from both Federal and non-Federal leases in that area under your 
tendering program.
    (ii) You also 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.
    (iii) MMS will provide additional criteria for approval of a 
tendering program in its ``Oil and Gas Payor Handbook.''
    (3) Value is the volume-weighted average gross proceeds accruing to 
the seller under your and your affiliates' arm's-length contracts for 
the purchase or sale of production from the field or area during the 
production month. The total volume purchased or sold under those 
contracts must exceed

[[Page 50]]

50 percent of your and your affiliates' production from both Federal and 
non-Federal leases in the same field or area during that month. Before 
calculating the volume-weighted average, you must normalize the quality 
of the oil in your or your affiliates' arms-length purchases or sales to 
the same gravity as that of the oil produced from the lease.
    (4) Value is the average of the daily mean spot prices published in 
any MMS-approved publication for WTI crude at Cushing, Oklahoma, during 
the trading month most concurrent with the production month. (For 
example, if the production month is June and the trading month is May 
26--June 25, compute the average of the daily mean prices using the 
daily Cushing spot prices published in the MMS-approved publication for 
all the business days between and including May 26 and June 25.)
    (i) Calculate the daily mean spot price by averaging the daily high 
and low prices for the period in the selected publication.
    (ii) Use only the days and corresponding spot prices for which such 
prices are published.
    (iii) You must adjust the value for applicable location and quality 
differentials, and you may adjust it for transportation costs, under 
Sec. 206.112.
    (iv) 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.
    (5) If you demonstrate to MMS's satisfaction that paragraphs (b)(2) 
through (b)(4) 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 average of the daily mean spot prices published in 
any MMS-approved publication:
    (i) For the market center nearest your lease for crude oil similar 
in quality to that of your production (for example, at the St. James, 
Louisiana, market center, spot prices are published for both Light 
Louisiana Sweet and Eugene Island crude oils--their quality 
specifications differ significantly); and
    (ii) During the trading month most concurrent with the production 
month. (For example, if the production month is June and the trading 
month is May 26-June 25, compute the average of the daily mean prices 
using the daily spot prices published in the MMS-approved publication 
for all the business days between and including May 26 and June 25 for 
the applicable market center.)
    (2) Calculate the daily mean spot price by averaging the daily high 
and low prices for the period in the selected publication. Use only the 
days and corresponding spot prices for which such prices are published. 
You must adjust the value for applicable location and quality 
differentials, and you may adjust it for transportation costs, under 
Sec. 206.112.
    (3) 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.
    (d) Unavailable or unreasonable index prices. If MMS determines that 
any of the index prices referenced in paragraphs (a), (b), and (c) of 
this section are unavailable or no longer represent 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 index price is 
unreasonable.
    (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

[[Page 51]]

    (ii) You must value your oil under this section at an index price; 
and
    (iii) You believe that use of the index price is unreasonable.
    (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 Sec. 206.112(b) unless it is included in the Director's approval.



Sec. 206.104  What index price publications are acceptable to MMS?

    (a) MMS periodically will publish in the Federal Register a list of 
acceptable index price publications 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 spot price estimates based on daily surveys of buyers and 
sellers of ANS and other 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 reference the tables you must use in the publications 
to determine the associated index prices.
    (d) MMS may revoke its approval of a particular publication if it 
determines that the prices published in the publication do not 
accurately represent spot market values.



Sec. 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.



Sec. 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.



Sec. 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;

[[Page 52]]

    (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 
Sec. 206.108.



Sec. 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.



Sec. 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 
Secs. 206.110 or 206.111, as applicable. This paragraph applies when:
    (1) You value oil under Sec. 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 index pricing. If you value oil using an index price 
under Sec. 206.103, MMS will allow a deduction for certain

[[Page 53]]

location/quality adjustments and certain costs associated with 
transporting oil as provided under Sec. 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 
Sec. 206.102 or Sec. 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 Secs. 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 Sec. 206.116.



Sec. 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 for transporting oil 
under that contract, except as provided in paragraphs (a)(1) and (a)(2) 
of this section and subject to the limitation in Sec. 206.109(c). You 
must be able to demonstrate that your contract is 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 
Sec. 206.111.
    (2) You must calculate the transportation allowance under 
Sec. 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) 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

[[Page 54]]

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.
    (c) 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.
    (d) 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.
    (e) 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.



Sec. 206.111  How do I determine a transportation allowance under a non-arm's-length transportation arrangement?

    (a) If you or your affiliate have a non-arm's-length transportation 
contract or no contract, including those situations where you or your 
affiliate perform your own transportation services, calculate your 
transportation allowance based on your or your affiliate's reasonable, 
actual transportation costs using the procedures provided in this 
section.
    (b) Base your transportation allowance for non-arm's-length or no-
contract situations on your or your affiliate's 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;
    (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.
    (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

[[Page 55]]

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 who owned 
the system on June 1, 2000.
    (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 the industrial bond yield index for 
Standard and Poor's BBB rating. Use the monthly average rate published 
in ``Standard and 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

[[Page 56]]

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.



Sec. 206.112  What adjustments and transportation allowances apply when I value oil using index pricing?

    When you use index pricing to calculate the value of production 
under Sec. 206.103, you must adjust the index price for location and 
quality differentials and you may adjust it for certain transportation 
costs, as specified in this section.
    (a) If you dispose of your production under one or more arm's-length 
exchange agreements, then each of the conditions in this paragraph 
applies.
    (1) You must adjust the index price for location/quality 
differentials. You must determine those differentials from each of your 
arm's-length exchange agreements applicable to the exchanged oil.
    (i) Therefore, for example, if you exchange 100 barrels of 
production from a given lease under two separate arm's-length exchange 
agreements for 60 barrels and 40 barrels respectively, separately 
determine the location/quality differential under each of those exchange 
agreements, and apply each differential to the corresponding index 
price.
    (ii) As another example, if you produce 100 barrels and exchange 
that 100 barrels three successive times under arm's-length agreements to 
obtain oil at a final destination, total the three adjustments from 
those exchanges to determine the adjustment under this subparagraph. (If 
one of the three exchanges was not at arm's length, you must request MMS 
approval under paragraph (b) of this section for the location/quality 
adjustment for that exchange to determine the total location/quality 
adjustment for the three exchanges.) You also could have a combination 
of these examples.
    (2) You may adjust the index price for actual transportation costs, 
determined under Sec. 206.110 or Sec. 206.111:
    (i) From the lease to the first point where you give your oil in 
exchange; and
    (ii) From any intermediate point where you receive oil in exchange 
to another intermediate point where you give the oil in exchange again; 
and
    (iii) From the point where you receive oil in exchange and transport 
it without further exchange to a market center, or to a refinery that is 
not at a market center.
    (b) For non-arm's-length exchange agreements, you must request 
approval from MMS for any location/quality adjustment.
    (c) If you transport lease production directly to a market center or 
to an alternate disposal point (for example, your refinery), you may 
adjust the index price for your actual transportation costs, determined 
under Sec. 206.110 or Sec. 206.111.
    (d) If you adjust for location/quality or transportation costs under 
paragraphs (a), (b), or (c) of this section, also adjust the index price 
for quality based on premia or penalties determined by pipeline quality 
bank specifications at intermediate commingling points or at the market 
center. Make this adjustment only if and to the extent that such 
adjustments were not already included in the location/quality 
differentials determined from your arm's-length exchange agreements.

[[Page 57]]

    (e) For leases in the Rocky Mountain Region, for purposes of this 
section, the term ``market center'' means Cushing, Oklahoma, unless MMS 
specifies otherwise through notice published in the Federal Register.
    (f) If you cannot determine your location/quality adjustment under 
paragraph (a) or (c) of this section, you must request approval from MMS 
for any location/quality adjustment.
    (g) You may not use any transportation or quality adjustment that 
duplicates all or part of any other adjustment that you use under this 
section.



Sec. 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.



Sec. 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.



Sec. 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.



Sec. 206.116  What interest and assessments apply if I improperly report a transportation allowance?

    (a) If you or your affiliate net a transportation allowance rather 
than report it as a separate entry against the royalty value on Form 
MMS-2014, you will be assessed an amount up to 10 percent of the netted 
allowance, not to exceed $250 per lease selling arrangement per sales 
period.
    (b) If you or your affiliate deduct 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 Sec. 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 file 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.



Sec. 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

[[Page 58]]

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.



Sec. 206.118  Are actual or theoretical losses permitted as part of a transportation allowance?

    You are allowed a deduction for oil transportation which results 
from payments that you make (either volumetric or for value) for actual 
or theoretical losses only under an arm's-length contract. You may not 
take such a deduction under a non-arm's-length contract.



Sec. 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) You may not claim a deduction from the royalty volume or royalty 
value for actual or theoretical losses except as provided in 
Sec. 206.118. 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.



Sec. 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.



Sec. 206.121  Is there any grace period for reporting and paying royalties after this subpart becomes effective?

    You may adjust royalties reported and paid for the three production 
months beginning June 1, 2000, without liability for late payment 
interest. This section applies only if the adjustment results from 
systems changes needed to comply with new requirements imposed under 
this subpart that were not requirements under the predecessor rule.



                         Subpart D--Federal Gas

    Source: 53 FR 1272, Jan. 15, 1988, unless otherwise noted.



Sec. 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 specific provisions of any statute or settlement 
agreement between the United States and a lessee resulting from 
administrative or judicial litigation, or oil and gas lease subject to 
the requirements of this subpart are inconsistent with any regulation in 
this subpart, then the lease, statute, or settlement agreement shall 
govern to the extent of that 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]

[[Page 59]]



Sec. 206.151  Definitions.

    For purposes of this subpart:
    Allowance means a deduction in determining value for royalty 
purposes. Processing allowance means an allowance for the reasonable 
costs for processing gas determined under this subpart. Transportation 
allowance means an allowance for the cost of moving royalty bearing 
substances (identifiable, measurable oil and gas, including gas that is 
not in need of initial separation) from the point at which it is first 
identifiable and measurable to the sales point or other point where 
value is established under this subpart.
    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 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.
    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

[[Page 60]]

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 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-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

[[Page 61]]

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.
    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.
    Selling arrangement means the individual contractual arrangements 
under which sales or dispositions of gas, residue gas and gas plant 
products are made. Selling arrangements are described by illustration in 
the MMS Royalty Management Program Oil and Gas Payor Handbook.
    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]



Sec. 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 
Sec. 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, Sec. 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

[[Page 62]]

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

[[Page 63]]

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 Royalty 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

[[Page 64]]

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. 
Sec. 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]



Sec. 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 
Sec. 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 Sec. 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

[[Page 65]]

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

[[Page 66]]

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 Royalty 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

[[Page 67]]

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]



Sec. 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 Sec. 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 Sec. 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

[[Page 68]]

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]



Sec. 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 Sec. 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 
Sec. 206.102 of this subpart; or (2) the value, for royalty purposes, of 
the gas prior to processing determined in accordance with Sec. 206.152 
of this subpart.
    (b) The requirement for accounting for comparison contained in the 
terms of leases will govern as provided in Sec. 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]



Sec. 206.156  Transportation allowances--general.

    (a) Where the value of gas has been determined pursuant to 
Sec. 206.152 or Sec. 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 Sec. 206.157.
    (c)(1) Except as provided in paragraph (c)(3) of this section, for 
unprocessed gas valued in accordance with Sec. 206.152 of this subpart, 
the transportation allowance deduction on the basis of a selling 
arrangement shall not exceed 50 percent of the value of the unprocessed 
gas determined in accordance with Sec. 206.152 of this subpart.
    (2) Except as provided in paragraph (c)(3) of this section, for gas 
production valued in accordance with Sec. 206.153 of this subpart the 
transportation allowance deduction on the basis of a selling

[[Page 69]]

arrangement shall not exceed 50 percent of the value of the residue gas 
or gas plant product determined in accordance with Sec. 206.153 of this 
subpart. For purposes of this section, natural gas liquids shall 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) 
shall contain all relevant and supporting documentation necessary for 
MMS to make a determination. Under no circumstances shall the value for 
royalty purposes under any selling arrangement be reduced to zero.
    (d) If, after a review and/or audit, MMS determines that a lessee 
has improperly determined a transportation allowance authorized by this 
subpart, then the lessee shall pay any additional royalties, plus 
interest, determined in accordance with 30 CFR 218.54, or shall be 
entitled to a credit, without interest. If the lessee takes a deduction 
for transportation on the 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 
line item, he may be assessed an additional amount under 206.157(d).

[53 FR 1272, Jan. 15, 1988, as amended at 61 FR 5465, Feb. 12, 1996; 64 
FR 43288, Aug. 10, 1999]



Sec. 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 line 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

[[Page 70]]

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 line 
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

[[Page 71]]

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 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)(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) A lessee may apply to the MMS for an exception from the 
requirement that it compute actual costs in accordance with paragraphs 
(b)(1) through (b)(4) of this section. The 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 both Federal and 
Indian leases) or a State regulatory agency (for Federal leases). The 
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 or State regulatory agency cost analysis exists and the FERC or 
State regulatory agency, as applicable, has declined to investigate 
pursuant to MMS timely objections upon filing; and (ii) the tariff 
significantly exceeds the lessee's actual costs for transportation as 
determined under this section.

[[Page 72]]

    (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-2014.
    (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 the Form MMS-2014.
    (ii) For new transportation facilities or arrangements, the lessee's 
initial deduction shall include estimates of the allowable gas 
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 FERC-approved or State 
regulatory agency-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.
    (d) Interest and assessments. (1) If a lessee nets a transportation 
allowance against the royalty value on the Form MMS-2014, the lessee 
shall be assessed an amount of up to 10 percent of the allowance netted 
not to exceed $250 per lease selling arrangement per sales period.
    (2) 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 Sec. 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.
    (3) 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.
    (4) 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. 
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

[[Page 73]]

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 unless the transportation allowance is based 
on a FERC or State regulatory-approved tariff;
    (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 Secs. 206.152(i) and 206.153(i) 
of this part.
    (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;

[[Page 74]]

    (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; and
    (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. 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]



Sec. 206.158  Processing allowances--general.

    (a) Where the value of gas is determined pursuant to Sec. 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 66\2/3\ percent of the value of each gas plant product 
determined in accordance with Sec. 206.153 of this subpart (such value 
to be reduced first for any transportation allowances related to 
postprocessing transportation authorized by Sec. 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 shall 
pay any additional royalties, plus interest determined in accordance 
with 30 CFR 218.54, or shall be entitled to a credit, without interest. 
If the lessee takes a deduction for processing on the Form

[[Page 75]]

MMS-2014 by improperly netting the allowance against the sales value of 
the gas plant products instead of reporting the allowance as a separate 
line item, he may be assessed an additional amount under 206.159(d).

[53 FR 1272, Jan. 15, 1988, as amended at 61 FR 5466, Feb. 12, 1996; 64 
FR 43288, Aug. 10, 1999]



Sec. 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 line 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 line entry on the 
Form MMS-2014. When necessary or appropriate, MMS may direct a lessee to 
modify its estimated or actual processing allowance.

[[Page 76]]

    (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.

[[Page 77]]

    (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-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 line 
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 and assessments. (1) If a lessee nets a processing 
allowance against the royalty value on the Form MMS-2014, the lessee 
shall be assessed an amount of up to 10 percent of the allowance netted 
not to exceed $250 per lease selling arrangement per sales period.
    (2) If a lessee deducts a processing allowance on its Form MMS-2014 
that exceeds 66\2/3\ percent of the value of the gas processed without 
obtaining prior approval of MMS under Sec. 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.
    (3) 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.
    (4) 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 without 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]



Sec. 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

[[Page 78]]

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: At 64 FR 43515, Aug. 10, 1999, unless otherwise noted.



Sec. 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.



Sec. 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

[[Page 79]]

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.

[[Page 80]]

    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 Sec. 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-

[[Page 81]]

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.
    Selling arrangement means the individual contractual arrangements 
under which sales or dispositions of gas, residue gas and gas plant 
products are made. Selling arrangements are described by illustration in 
the ``MMS Royalty Management Program Oil and Gas Payor Handbook.''
    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.



Sec. 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 Sec. 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 Sec. 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

[[Page 82]]

contract settlement and if the royalty-bearing contract settlement 
proceeds per MMBtu added to the 80 percent of the safety net prices 
calculated at Sec. 206.172(e)(4)(i) exceeds the index-based value that 
applies to the gas under this section (including any adjustments 
required under Sec. 206.176), then the value of the gas is the higher of 
the value determined under this section (including any adjustments 
required under Sec. 206.176) or Sec. 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 Sec. 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 Sec. 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 
Sec. 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;

[[Page 83]]

    (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 Secs. 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  x  S) - (1.25  x  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  x  V  x  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

[[Page 84]]

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 Sec. 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 Sec. 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 Sec. 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 Sec. 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.



Sec. 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 
Sec. 206.176, you have two choices. You may elect to perform the dual 
accounting calculation according to either Sec. 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

[[Page 85]]

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 Sec. 206.172 or Sec. 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 Sec. 206.172 or 
Sec. 206.174, as follows:
    (i) Value of gas after processing = (value determined under either 
Sec. 206.172 or Sec. 206.174, as applicable)  x  (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:

------------------------------------------------------------------------
                                                 Increment    Increment
                                                 if Lessee    if lessee
                                                   has no       has an
                   BTU range                     ownership    ownership
                                                interest in  interest in
                                                   plant        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.

[[Page 86]]

    (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.



Sec. 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 Sec. 206.174(b) or the value under Sec. 206.172.
    (iii) Also use this section to value any other gas production that 
cannot be valued under Sec. 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 
Sec. 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 Sec. 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

[[Page 87]]

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

[[Page 88]]

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 Sec. 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

[[Page 89]]

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.
    (l) Time limits on adjustments and audits for certain Indian leases. 
(1) If you determine the value of production under this section from 
leases in Montana and North Dakota, you have time limits to make 
adjustments to your reported royalty value. If you know of an adjustment 
that would result in additional royalty owed, you are required to report 
that adjustment and pay the additional royalty by the time limit 
established in this paragraph. MMS also has time limits to complete 
royalty audits for these leases only. There are exceptions to these time 
limits in paragraph (l)(2) of this section.
    (i) If your royalty valuation does not include a non-arm's-length 
allowance under this subpart, you have until the last day of the 13th 
month following the production month to report any adjustments on Form 
MMS-2014. MMS must complete royalty audits timely and may not issue 
demands or orders or initiate other action to collect royalty 
underpayment for this production from the lessee after the last day of 
the 12th month following the last day to make adjustments.
    (ii) If your royalty valuation includes a non-arm's-length allowance 
under this subpart, you have until the last day of the 9th month 
following the month you submit to MMS your actual transportation 
allowance report, or your actual processing allowance report, to report 
any adjustments on Form MMS-2014. MMS must complete royalty audits 
timely and may not issue demands or orders or initiate any other action 
to collect royalty underpayments for this production from the lessee 
after the last day of the 12th month following the last day to report 
adjustments.
    (2) Exceptions to the time limits in paragraph (l)(1) of this 
section are as follows:
    (i) If you have a pending dispute with your purchaser or with the 
person

[[Page 90]]

transporting or processing your gas production that affects valuation, 
the time periods to make adjustments in paragraphs (l)(1)(i) and (ii) of 
this section will be extended for 6 months after your dispute is finally 
resolved. The time period to complete audits and issue demands or orders 
is correspondingly extended;
    (ii) If there is a written agreement between you and MMS or its 
delegee (if applicable) to extend the time limit, the time period is 
extended for the period stated in the agreement;
    (iii) If there is a pending regulatory proceeding by any agency with 
jurisdiction over sales prices for gas that could affect the value of 
the gas, the time period to make adjustments in paragraphs (l)(1)(i) and 
(ii) of this section will be extended for 90 days after final resolution 
of the pending regulatory proceeding, including any period for judicial 
review. The time period to complete audits and issue demands or orders 
is correspondingly extended;
    (iv) If the lessee fails or refuses to provide records or 
information in its possession or control necessary to complete the 
audit, the time period to issue demands or orders will be extended for 
any time periods that MMS cannot obtain the records or information; and
    (v) The time period in paragraphs (l)(1)(i) and (ii) of this section 
will not apply in situations involving fraud or intentional 
misrepresentation or concealment of a material fact for the purpose of 
evading a payment obligation.
    (3) For purposes of this paragraph (l), demand or order means an 
order to pay a specific amount or an amount that the lessee may easily 
calculate. It also includes an order to perform a restructured 
accounting based upon repeated, systemic reporting errors for a 
significant number of leases or a single lease for a significant number 
of reporting months. The order to perform a restructured accounting must 
specify the reasons and the factual bases for the order.
    (4) If an audit discloses overpayments for any lease, the lessee may 
credit those overpayments against any underpayments due on that same 
lease.



Sec. 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

[[Page 91]]

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.



Sec. 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 Sec. 206.172 or Sec. 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 Sec. 206.52, less applicable allowances.
    (2) The value of the gas prior to processing determined under either 
Sec. 206.172 or Sec. 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 
Sec. 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 Sec. 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 Sec. 206.173(b)(4)(ii) to determine if 
you must perform a dual accounting calculation.

                        Transportation Allowances



Sec. 206.177  What general requirements regarding transportation allowances apply to me?

    (a) When you value gas under Sec. 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

[[Page 92]]

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 Sec. 206.178.
    (c)(1) Except as provided in paragraphs (c)(2) and (3) of this 
section, your transportation allowance deduction for each selling 
arrangement 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 selling arrangement 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.



Sec. 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

[[Page 93]]

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

[[Page 94]]

(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.

[[Page 95]]

    (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 line 
item 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

[[Page 96]]

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 Sec. 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.

                          Processing Allowances



Sec. 206.179  What general requirements regarding processing allowances apply to me?

    (a) When you value any gas plant product under Sec. 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 Sec. 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 
Sec. 206.177.

[[Page 97]]

    (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.



Sec. 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

[[Page 98]]

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

[[Page 99]]

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 line 
item 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.



Sec. 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 Sec. 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 Secs. 206.179 and 
206.180.

[[Page 100]]



                         Subpart F--Federal Coal

    Source: 54 FR 1523, Jan. 13, 1989, unless otherwise noted.



Sec. 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 Mineral 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]



Sec. 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

[[Page 101]]

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-2014.
    Person means by individual, firm, corporation, association, 
partnership, consortium, or joint venture.
    Selling arrangement means the individual contractual arrangements 
under which sales or dispositions of coal are made to a purchaser.
    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]



Sec. 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 clearance 
numbers are identified in 30 CFR 210.10 and 30 CFR 216.10.



Sec. 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

[[Page 102]]

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]



Sec. 206.254  Quality and quantity measurement standards for reporting and paying royalties.

    (a) For leases subject to Sec. 206.257 of this subpart, the quality 
of coal on which royalty is due shall be reported on the basis of 
percent sulfur, percent ash, and number of British thermal units (Btu) 
per pound of coal. Coal quality determinations shall be made at 
intervals prescribed in the lessee's sales contract. If there is no 
contract, or if the contract does not specify the intervals of coal 
quality determination, the lessee shall propose a quality test schedule 
to MMS. In no case, however, shall quality tests be performed less than 
quarterly using standard industry-recognized testing methods. Coal 
quality information shall be reported on the appropriate forms required 
under 30 CFR part 216.
    (b) 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 shall 
be reported on appropriate forms required under 30 CFR part 216 and on 
the Report of Sales and Royalty Remittance, Form MMS-2014, as required 
under 30 CFR part 210.

[54 FR 1523, Jan. 13, 1989, as amended at 57 FR 52720, Nov. 5, 1992]



Sec. 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 Sec. 206.256(d) of this subpart.

[54 FR 1523, Jan. 13, 1989, as amended at 61 FR 5480, Feb. 12, 1996]



Sec. 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

[[Page 103]]

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 Sec. 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]



Sec. 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 Secs. 206.258 through 206.262 of this 
subpart, or any allowance authorized by Sec. 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

[[Page 104]]

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 Royalty 
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-2014 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 Secs. 206.258 through 
206.262 and Sec. 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

[[Page 105]]

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 Sec. 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]



Sec. 206.258  Washing allowances--general.

    (a) For ad valorem leases subject to Sec. 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 
Sec. 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]



Sec. 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

[[Page 106]]

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-2014.
    (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-2014. 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

[[Page 107]]

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-2014.
    (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-2014.
    (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-2014, then the lessee shall be assessed an 
amount up to 10 percent of the allowance netted not to exceed $250 per 
lease selling arrangement 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-2014 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-2014 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-2014 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]



Sec. 206.260  Allocation of washed coal.

    (a) When coal is subjected to washing, the washed coal must be 
allocated

[[Page 108]]

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.



Sec. 206.261  Transportation allowances--general.

    (a) For ad valorem leases subject to Sec. 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]



Sec. 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-2014.
    (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

[[Page 109]]

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-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 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

[[Page 110]]

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-2014.
    (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-2014.
    (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-2014, the lessee shall be assessed an amount of up 
to 10 percent of the allowance netted not to exceed $250 per lease 
selling arrangement 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-2014 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-2014 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-2014 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

[[Page 111]]

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]



Sec. 206.263  Contract submission.

    (a) The lessee and other payors shall submit to MMS, upon request, 
contracts for the sale of coal from ad valorem leases subject to this 
subpart. The MMS must receive the contracts within a reasonable period 
of time, as specified by MMS. Lessees shall include as part of the 
submittal requirements any contracts, agreements, contract amendments, 
or other documents that affect the gross proceeds received for the sale 
of coal, as well as any other information regarding any consideration 
received for the sale or disposition of coal that is not included in 
such contracts. At the time of its contract submittals, MMS may require 
the lessee to certify in writing that it has provided all documents and 
information that reflect the total consideration provided by purchasers 
of coal from ad valorem leases subject to this subpart. Information 
requested under this section may include contracts for both ad valorem 
and cents-per-ton leases and shall be available in the lessee's offices 
during normal business hours or provided to MMS at such time and in such 
manner as may be requested by authorized Department of the Interior 
personnel. Any oral sales arrangement negotiated by the lessee must be 
placed in a written form and be retained by the lessee. Nothing in this 
section shall be construed to limit the authority of MMS to obtain or 
have access to information pursuant to 30 CFR part 212.
    (b) Lessees and other payors shall designate, for each contract 
submitted under this section, whether the contract is arm's-length or 
non-arm's-length.
    (c) A lessee's or other payor's determination that its contract is 
arm's-length is subject to future audit to verify that the contract 
meets the criteria of the arm's-length contract definition in 
Sec. 206.251 of this subpart.
    (d) Information required to be submitted under this section that 
constitutes trade secrets and commercial and financial information that 
is identified as privileged or confidential shall not be available for 
public inspection or made public or disclosed without the consent of the 
lessee or other payor, except as otherwise provided by law or 
regulation.

[54 FR 1523, Jan. 13, 1989, as amended at 65 FR 43289, Aug. 10, 1999]



Sec. 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]



Sec. 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 Sec. 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 Sec. 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 Sec. 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 
Sec. 206.259(b)(2)(v) of this subpart.

[[Page 112]]



                     Subpart G--Other Solid Minerals



Sec. 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: 56 FR 57276, Nov. 8, 1991, unless otherwise noted.



Sec. 206.350  Purpose and scope.

    (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.). The purpose of this 
subpart is to establish the value of geothermal production for royalty 
purposes.
    (b) All royalty payments made to MMS are subject to audit and 
adjustment.



Sec. 206.351  Definitions.

    For purposes of this subpart:
    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:
    (1) Ownership in excess of 50 percent constitutes control;
    (2) Ownership of 10 through 50 percent creates a rebuttable 
presumption of control; and
    (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. The MMS may require the lessee to certify the claimed nature 
of ownership control. To be considered arm's-length for any production 
month, a contract must meet the requirements of this definition for the 
production month as well as when the contract was executed.
    Audit means a procedure having the same meaning and effect as that 
described at 30 CFR part 217 for verifying royalty payment compliance 
activities of lessees or other authorized persons who pay royalties, 
rents, or bonuses on Federal geothermal leases.
    Byproduct means:

[[Page 113]]

    (1) Any mineral or minerals (exclusive of oil, hydrocarbon gas, and 
helium) which are found in solution or developed in association with 
geothermal fluids and which have a value of less than 75 per centum of 
the value of the geothermal energy or are not, because of quantity, 
quality, or technical difficulties in extraction and production, of 
sufficient value to warrant extraction and production by themselves, and
    (2) Commercially demineralized water.
    Byproduct recovery facility means the facility or facilities at 
which byproducts are placed in marketable condition.
    Byproduct transportation allowance means an approved allowance for 
the lessee's reasonable, actual costs, excluding gathering, incurred for 
moving byproducts, including commercially demineralized water, to a 
point of sale or point of delivery off the lease, unit area, or 
communitized area.
    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 used in the geothermal netback 
procedure for determining the value of geothermal resources utilized by 
the lessee to generate electricity. Transmission deduction means a 
deduction for the lessee's reasonable actual costs incurred to wheel or 
transmit the electricity from the lessee's powerplant to the purchaser's 
delivery point. Generating deduction means a deduction for the lessee's 
reasonable, actual costs of generating plant tailgate electricity.
    Delivered electricity means the amount of electricity in 
kilowatthours delivered to the purchaser.
    Direct utilization means any process other than electrical 
generation in which the thermal energy of the geothermal resource is 
utilized, including, but not limited to, space heating, greenhouse 
operations, and industrial or agricultural process heat.
    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 efficient movement of lease production from the 
wellhead to the point of utilization.
    Geothermal netback procedure means the method of determining the 
value of geothermal resources that are utilized in a lessee-owned 
powerplant for the generation and sale of electricity by deducting the 
lessee's reasonable, actual transmission and generating costs from the 
sales price or value of the electricity to derive the value of the 
geothermal resource at the powerplant inlet.
    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.
    Geothermal utilization facility means a powerplant or direct 
utilization facility that utilizes the heat or other energy of the 
geothermal resource.
    Gross proceeds (for royalty purposes) means the total monies and 
other consideration accruing to a geothermal lessee for any disposition 
of geothermal resources, including total payments for the sale of 
electricity generated by the lessee from lease-produced geothermal 
resources. Gross proceeds includes, but is not limited to, payments to 
the lessee for certain services such as effluent injection, field 
operation and maintenance, drilling or workover of wells, and/or field 
gathering to the extent that the lessee is obligated to perform them at 
no cost to the Federal Government. Gross proceeds also includes, but is 
not limited to, 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

[[Page 114]]

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 a geothermal lease issued under authority of the 
Geothermal Steam Act of 1970, as amended (30 U.S.C. 1001 et seq.), 
unless the context indicates otherwise.
    Lessee means any person to whom the United States issues a 
geothermal 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 geothermal lease as well as an operator 
or payor who has no interest in the lease but who has assumed the 
royalty payment responsibility. This also includes any affiliate of the 
lessee that utilizes the geothermal resource to generate electricity, in 
a direct utilization process, or to recover byproducts, or any affiliate 
that transports lease production.
    Like-quality lease products means lease products that have similar 
chemical, physical, and legal characteristics.
    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.
    Minimum royalty means the minimum amount of annual royalty as 
specified in the lease or in applicable leasing regulations that the 
lessee must pay after commencement of geothermal production in 
commercial quantities.
    No sales means the utilization or disposal of geothermal resources 
without the benefit of a sale.
    Person means any individual, firm, corporation, association, 
partnership, consortium, or joint venture (when established as a 
separate entity).
    Plant tailgate electricity means the amount of electricity in 
kilowatthours generated by the powerplant exclusive of plant parasitic 
electricity, but inclusive of any electricity generated by the 
powerplant 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 powerplant or direct utilization 
facility in which the geothermal resource (steam or hot water) is 
utilized.
    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 utilization operations.
    Secretary means the Secretary of the Department of the Interior or 
any person duly authorized to exercise the powers vested in that office.
    Selling arrangement means the individually contracted arrangements 
under which sales or dispositions of geothermal resources are made, 
including sales or dispositions of byproducts and electricity sales 
where the lessee generates electricity from lease geothermal production.
    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 1 year.
    Wheeling means the transmission of electricity from a powerplant to 
the point of delivery.



Sec. 206.352  Valuation standards for electrical generation.

    (a) The value of geothermal resources produced from leases subject 
to this subpart and used to generate electricity shall be determined 
pursuant to this section.
    (b)(1)(i) The value of geothermal resources that are sold pursuant 
to an arm's-length contract shall be the gross proceeds accruing to the 
lessee, except as provided in paragraphs (b)(1)(ii) and (b)(1)(iii) 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.
    (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 geothermal 
resource. If the contract does not reflect the total consideration, MMS 
may require that the

[[Page 115]]

geothermal resource sold pursuant to that contract be valued in 
accordance with paragraph (d) of this section. Value shall not be less 
than the gross proceeds accruing to the lessee, including any additional 
consideration received.
    (iii) 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, MMS shall require the geothermal resource 
to be valued pursuant to paragraph (d) of this section, and notification 
provided to MMS in accordance with paragraph (e)(3) of this section. If 
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.
    (2) The MMS may require a lessee to certify that the provisions in 
its arm's-length contract include all of the consideration to be paid by 
the buyer, either directly or indirectly, for the geothermal resource.
    (c)(1) The value of geothermal resources subject to this section 
that are sold under a non-arm's-length contract shall be determined in 
accordance with the first applicable of the following paragraphs:
    (i) The gross proceeds accruing to the lessee pursuant to a sale 
under its non-arm's-length contract provided that those gross proceeds 
are not less than the gross proceeds derived from or paid under the 
lowest-priced available comparable arm's-length contract for sales of 
geothermal resources to the lessee-affiliate's same powerplant (the 
``minimum value''). If the gross proceeds under the lessee's non-arm's-
length contract are less than the ``minimum value'' under available 
comparable arm's-length contracts, or if there are no available 
comparable arm's-length contracts, value will be determined by the 
weighted average of the gross proceeds established under arm's-length 
contracts for the sale of significant quantities of geothermal resources 
to the same powerplant. Available contracts will mean contracts in the 
possession of the lessee, the lessee's affiliate, or MMS. In evaluating 
the comparability of arm's-length contracts for the purposes of these 
regulations, the following factors shall be considered: Time of 
execution, duration, terms, quality of the geothermal resource, volume, 
dedication to the same powerplant, and other factors that may be 
appropriate to reflect the value of the resource;
    (ii) The value determined by the geothermal netback procedure. Under 
the geothermal netback procedure, the lessee's reasonable actual costs 
for the generation and transmission of electricity shall be deducted 
from the lessee's gross proceeds received for the sale of electricity to 
determine the value of the geothermal resource. Transmission deductions 
shall be determined pursuant to Sec. 206.353 of this part. Generating 
deductions shall be determined pursuant to Sec. 206.354 of this part; or
    (iii) A value determined by any other reasonable valuation method 
approved by MMS.
    (2) Value determinations made pursuant to this paragraph are subject 
to the notification requirements of paragraph (e) of this section.
    (d)(1) The value of geothermal resources subject to this section 
that are not subject to a sales transaction (``no sales'' geothermal 
resources) but are instead utilized directly by the lessee in its own 
powerplant for the generation and sale of electricity shall be 
determined in accordance with the first applicable of the following 
paragraphs:
    (i) 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 powerplant. In 
evaluating the acceptability of arm's-length contracts, the following 
factors shall 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;
    (ii) The value determined by the geothermal netback procedure. Under 
the geothermal netback procedure, the lessee's reasonable actual costs 
for the

[[Page 116]]

generation and transmission of electricity shall be deducted from the 
lessee's gross proceeds received for the sale of electricity to 
determine the value of the geothermal resource. Transmission deductions 
shall be determined pursuant to Sec. 206.353 of this part. Generating 
deductions shall be determined pursuant to Sec. 206.354 of this part; or
    (iii) A value determined by any other reasonable valuation method 
approved by MMS.
    (2) Value determinations made pursuant to this paragraph are subject 
to the notification requirements of paragraph (e) of this section.
    (e)(1) Pursuant to subpart H of 30 CFR part 212, the lessee shall 
retain all data relevant to the determination of royalty value, 
particularly where the value is determined pursuant to paragraph (c) or 
(d) of this section. 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) Upon request, lessees shall make available to authorized MMS 
representatives or to other authorized persons any and all contracts for 
the sale or other disposition of the lease production; contracts for the 
sale, generation, and/or transmission of electricity attributable to 
lease production; and any arm's-length sales and other data for like-
quality production sold, purchased, or otherwise obtained by the lessee 
from the field as may be necessary to support a value determination.
    (3) A lessee shall notify MMS if it has determined value pursuant to 
paragraph (c) or (d) of this section. The notification shall be by 
letter to the MMS Associate Director for Royalty 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) or (d) 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 
218.302. 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 consistent with 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 where geothermal 
resources are directly sold.
    (i) The lessee is required to place geothermal resources in 
marketable condition and to deliver geothermal resources to the 
powerplant at no cost to the Federal 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 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 geothermal resource in marketable condition or 
deliver it to the powerplant.
    (j) Value shall be based on the highest price a prudent lessee can 
receive through legally enforceable claims

[[Page 117]]

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 the 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 
geothermal resources.
    (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 value 
determinations 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 regulations of the Department, 43 CFR part 2.



Sec. 206.353  Determination of transmission deductions.

    (a) Where the value of geothermal energy is determined by the 
geothermal netback procedure pursuant to paragraphs (c)(1)(ii) and 
(d)(1)(ii) of Sec. 206.352 of this subpart, a transmission deduction 
shall be subtracted from the lessee's gross proceeds received for the 
sale of electricity to determine the plant tailgate value of the 
electricity. The transmission deduction consists of either or both of 
two components:
    (1) Transmission line costs as determined pursuant to paragraph (b) 
of this section, and
    (2) Wheeling costs if the electricity is transmitted across a third-
party's transmission line under an arm's-length wheeling agreement. 
Transmission deductions are subject to the limitation prescribed in 
paragraph (c) of this section.
    (b)(1) Transmission-line costs shall be based on the lessee's actual 
costs associated with the construction and operation of a transmission 
line for the purpose of transmitting electricity attributable and 
allocable to the lessee's powerplant utilizing Federal geothermal 
resources. The monthly transmission line cost component of the 
transmission deduction is determined by multiplying the annual 
transmission line cost rate (in dollars per kilowatthour) by the amount 
of electricity delivered for the reporting month. The transmission line 
cost rate shall be redetermined annually at the beginning of the same 
month of the year in which the transmission line was placed into 
service, the same month of the year in which the powerplant was placed 
into service, or, at the lessee's option, at a time concurrent with the 
beginning of the lessee's annual corporate accounting period; Provided, 
however, the period selected must coincide with the same period chosen 
for the generating deduction pursuant to Sec. 206.354(b)(1). After a 
deduction period is chosen, the lessee may not later elect to use a 
different deduction period without MMS approval.
    (2) Allowable transmission-line 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 capital investment 
in the transmission line 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 assets, including costs of 
delivery and installation of capital equipment, that

[[Page 118]]

are an integral part of the transmission line. A return on capital 
invested in the purchase of real estate for transmission facilities may 
be allowed provided that the lessee demonstrates the necessity for such 
purchase, the purchased land is not on a Federal geothermal lease, and 
MMS approves the deduction; the rate of return shall be the same rate 
determined in paragraph (b)(2)(v) of this section.
    (i) Allowable operating expenses include operations supervision and 
engineering, operations labor, materials, ad valorem property taxes, 
rent, supplies, and any other directly allocable and attributable 
operating expenses that the lessee can document.
    (ii) Allowable maintenance expenses include maintenance of the 
transmission line, maintenance of equipment, maintenance labor, and 
other directly allocable and attributable maintenance expenses that the 
lessee can document.
    (iii) 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.
    (iv) 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. After a lessee has 
elected to use either method, the lessee may not later elect to change 
to the other alternative without MMS approval.
    (A) To compute depreciation, the lessee must use a straight-line 
depreciation method based on the expected life of the geothermal 
project, usually the term of the electricity sales contract or other 
depreciation period acceptable to MMS. A change in ownership of a 
transmission line shall not alter the depreciation schedule established 
by the original lessee-owner for purposes of computing transmission line 
costs. With or without a change in ownership, a transmission line shall 
be depreciated only once. The rate of return used to compute the return 
on undepreciated capital investment shall be determined pursuant to 
paragraph (b)(2)(v) of this section.
    (B) To compute a return on capital investment, the allowed cost 
shall be the amount equal to the allowable capital investment in the 
transmission line 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 transmission 
lines first placed into service on or after March 1, 1988.
    (v) The rate of return shall be 2 times Standard and Poor's 
industrial BBB bond rate. The rate of return shall be 2 times the 
monthly average rate as published in Standard and Poor's Bond Guide for 
the first month of the annual deduction period and shall be effective 
during the following deduction period. The rate shall be redetermined 
annually at the beginning of the same month beginning the annual 
deduction period chosen pursuant to paragraph (b)(1) of this section.
    (3) Transmission-line cost rates, determined annually, are computed 
by dividing the sum of the operating, maintenance, overhead, and capital 
costs by the annual amount of delivered electricity.
    (4) For new transmission lines, the lessee's costs for the first 
deduction period shall be based on estimated expenses (including 
overhead) for operating and maintaining the transmission line. For 
subsequent deduction periods, the transmission line costs shall be 
estimated based on the lessee's actual operating and maintenance 
expenses for the previous period adjusted for decreases or increases 
that the lessee knows will affect the deduction in the current period.
    (c) Under no circumstances shall the transmission deduction plus the 
generating deduction determined pursuant to Sec. 206.354 of this subpart 
reduce the royalty value of the geothermal resource to zero.
    (d)(1) If the actual transmission deduction determined at the end of 
the annual reporting period is less than the amount the lessee estimated 
and used in the netback procedure during the reporting period, the 
lessee shall be required to pay additional royalties retroactive to the 
first month of the reporting period, plus interest computed

[[Page 119]]

pursuant to 30 CFR 218.302. If the actual transmission deduction is 
greater than the amount applied in the netback calculation, the lessee 
shall be entitled to a credit.
    (2) Lessees must submit corrected Forms MMS-2014 to reflect 
adjustments to royalty payments in accordance with MMS instructions.
    (e)(1) All transmission deductions are subject to review, audit, and 
adjustment. When necessary or appropriate, MMS may direct a lessee to 
modify its estimated or actual transmission deduction and adjust royalty 
values accordingly.
    (2) Pursuant to subpart H of 30 CFR part 212, the lessee must 
maintain all data and records supporting its transmission deduction, 
including wheeling and other transmission-related agreements. These data 
and records must be made available to MMS and other authorized personnel 
upon request, and shall be maintained in a confidential manner in 
accordance with applicable laws and regulations pursuant to Sec. 206.352 
of this subpart.
    (f) A one-time refund of royalties equal to the royalty amount of 
actual dismantlement costs attributable to the transmission line that 
are in excess of actual income attributable to the salvage of the 
transmission line will be allowed at the completion of the dismantlement 
and salvage operations.



Sec. 206.354  Determination of generating deductions.

    (a) Where the value of geothermal energy is determined by the 
geothermal netback procedure pursuant to paragraphs (c)(1)(ii) and 
(d)(1)(ii) of Sec. 206.352 of this subpart, that value shall be 
determined by deducting the lessee's reasonable actual costs incurred to 
generate electricity from the plant tailgate value of the electricity 
(usually the transmission-reduced value of the delivered electricity). 
Generating deductions are subject to the limitation prescribed in 
paragraph (c) of this section.
    (b)(1) Generating costs shall be based on the lessee's actual annual 
costs associated with the construction and operation of a geothermal 
powerplant. The monthly generating deduction is determined by 
multiplying the annual generating cost rate (in dollars per 
kilowatthour) 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 plant tailgate electricity and must 
be redetermined annually at the beginning of the same month of the year 
in which the powerplant was placed into service or, at the lessee's 
option, at a time concurrent with the beginning of the lessee's annual 
corporate accounting period; Provided, however, the period selected must 
coincide with the same period chosen for the transmission deduction 
pursuant to Sec. 206.353(b)(1). After a deduction period is chosen, the 
lessee may not later elect to use a different deduction period without 
MMS approval.
    (2) Allowable generating 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 capital investment 
in the powerplant 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 assets, including costs of 
delivery and installation of capital equipment, that are an integral 
part of the powerplant or are required by the design specifications of 
the power conversion cycle. A return on capital invested in the purchase 
of real estate for a powerplant site may be allowed provided that the 
lessee demonstrates the necessity for such purchase, the purchased land 
is not on a Federal geothermal lease, and MMS approves the deduction; 
the rate of return shall be the same rate determined in paragraph 
(b)(2)(v) of this section. The costs of gathering systems and other 
production-related facilities are not allowed.
    (i) Allowable operating expenses include operations supervision and 
engineering, operations labor, materials, ad valorem property taxes, 
rent, supplies, auxiliary fuel and/or utilities used to operate the 
powerplant during down time, and any other directly allocable and 
attributable operating expense that the lessee can document.

[[Page 120]]

    (ii) Allowable maintenance expenses include maintenance of the 
powerplant, maintenance of equipment, maintenance labor, and other 
directly allocable and attributable maintenance expenses that the lessee 
can document.
    (iii) Overhead directly attributable and allocable to the operation 
and maintenance of the powerplant is an allowable expense. State and 
Federal income taxes and severance taxes, including royalties, are not 
allowable expenses.
    (iv) 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. After a lessee has 
elected to use either method, the lessee may not later elect to change 
to the other alternative without MMS approval.
    (A) To compute depreciation, the lessee 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. A change in ownership of a powerplant shall not alter 
the depreciation schedule established by the original lessee-owner for 
computing the generating costs. With or without a change in ownership, a 
powerplant shall be depreciated only once. The rate of return used to 
compute the return on undepreciated capital investment shall be 
determined pursuant to paragraph (b)(2)(v) of this section.
    (B) To compute a return on capital investment, the allowed cost 
shall be the amount equal to the allowable capital investment in the 
powerplant 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 powerplants first 
placed into service on or after March 1, 1988.
    (v) The rate of return shall be 2 times Standard and Poor's 
industrial BBB bond rate. The rate of return shall be 2 times the 
monthly average rate as published in Standard and Poor's Bond Guide for 
the first month of the annual deduction period and shall be effective 
during the following deduction period. The rate shall be redetermined 
annually at the beginning of the same month beginning the annual 
deduction period chosen pursuant to paragraph (b)(1) of this section.
    (3) Generating cost rates, determined annually, shall be computed by 
dividing the sum of the operating, maintenance, overhead, and capital 
costs by the annual amount of plant tailgate electricity.
    (4) For new powerplants, the lessee's generating costs for the first 
deduction period shall be based on estimated expenses (including 
overhead) for operating and maintaining the powerplant. For subsequent 
deduction periods, the generating costs shall be estimated based on the 
lessee's actual operating and maintenance expenses for the previous 
period adjusted for decreases or increases that the lessee knows will 
affect the deduction in the current period.
    (c) Under no circumstances shall the generating deduction plus the 
transmission deduction determined pursuant to Sec. 206.353 of this 
subpart reduce the royalty value of the geothermal resource to zero.
    (d)(1) If the actual generating deduction determined at the end of 
the annual reporting period is less than the amount the lessee estimated 
and used in the netback procedure during the reporting period, the 
lessee shall be required to pay additional royalties retroactive to the 
first month of the reporting period, plus interest computed pursuant to 
30 CFR 218.302. If the actual generating deduction is greater than the 
amount applied in the netback calculation, the lessee shall be entitled 
to a credit.
    (2) Lessees must submit corrected Forms MMS-2014 to reflect 
adjustments to royalty payments in accordance with MMS instructions.
    (e)(1) All generating deductions are subject to review, audit, and 
adjustment. When necessary or appropriate, MMS may direct a lessee to 
modify its estimated or actual generating deduction and adjust royalty 
values accordingly.
    (2) Pursuant to subpart H of 30 CFR part 212, the lessee must 
maintain all data and records supporting its generating deduction. These 
data and records must be made available to

[[Page 121]]

MMS and other authorized personnel upon request, and shall be maintained 
in a confidential manner in accordance with applicable laws and 
regulations pursuant to Sec. 206.352 of this subpart.
    (f) A one-time refund of royalties equal to the royalty amount of 
actual dismantlement costs attributable to the powerplant that are in 
excess of actual income attributable to the salvage of the powerplant 
will be allowed at the completion of the dismantlement and salvage 
operations.



Sec. 206.355  Valuation standards for direct utilization.

    (a) The value of geothermal resources produced for leases subject to 
this subpart and used in direct utilization processes shall be 
determined pursuant to this section.
    (b)(1)(i) The value of geothermal resources that are sold pursuant 
to an arm's-length contract shall be the gross proceeds accruing to the 
lessee, except as provided in paragraphs (b)(1)(ii) and (b)(1)(iii) 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.
    (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 geothermal resource. If the contract does not reflect the total 
consideration, MMS may require that the geothermal resource sold 
pursuant to that contract be valued in accordance with paragraph (d) of 
this section. Value shall not be less than the gross proceeds accruing 
to the lessee, including any additional consideration received.
    (iii) 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 geothermal resource 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, MMS shall require the geothermal 
resource to be valued pursuant to paragraph (d) 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.
    (2) 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 geothermal resource.
    (c)(1) The value of geothermal resources subject to this section 
that are sold under a non-arm's-length contract shall be determined in 
accordance with the first applicable of the following paragraphs:
    (i) The gross proceeds accruing to the lessee pursuant to a sale 
under its non-arm's-length contract provided that those gross proceeds 
are not less than the gross proceeds derived from or paid under the 
lowest-priced available comparable arm's-length contract for sales of 
geothermal resources to the lessee-affiliate's same direct utilization 
facility (the ``minimun value''). If the gross proceeds under the 
lessee's non-arm's-length contract are less than the ``minimum value'' 
under available comparable arm's-length contracts, or if there are no 
available comparable arm's-length contracts, value will be determined by 
the weighted average of the gross proceeds established under arm's-
length contracts for the sale of significant quantities of geothermal 
resources to the same direct utilization facility. Available contracts 
will mean contracts in the possession of the lessee, the lessee's 
affiliate, or MMS. In evaluating the comparability of arm's-length 
contracts for the purposes of these regulations, the following factors 
shall be considered: Time of execution, duration, terms, quality of the 
geothermal resource, volume, dedication to the same direct utilization 
facility, and other factors that may be appropriate to reflect the value 
of the resource;
    (ii) The equivalent value of the least expensive, reasonable 
alternative energy source (fuel). The equivalent value of the least 
expensive, reasonable alternative energy source shall be

[[Page 122]]

based on the amount of thermal energy that would otherwise be used by 
the direct utilization process in place of the geothermal resource. That 
amount of thermal energy (in Btu's) displaced by the geothermal resource 
shall be determined by the equation

thermal energy displaced =
[GRAPHIC] [TIFF OMITTED] TC15NO91.017


where hin is the enthalpy in Btu's/lb at the utilization 
facility inlet (based on measured inlet temperature), hout is 
the enthalpy in Btu's/lb at the facility outlet (based on measured 
outlet temperature), density is in lbs/cu ft based on inlet temperature, 
the factor 0.133681 (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 of the 
alternative energy source shall 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 shall be determined and approved by BLM; or
    (iii) A value determined by any other reasonable valuation method 
approved by MMS.
    (2) Valuations made pursuant to this paragraph are subject to the 
notification requirements of paragraph (e) of this section.
    (d)(1) The value of geothermal resources subject to this section 
that are not subject to a sales transaction but are instead used by the 
lessee in its own direct utilization facility (``no sales'' geothermal 
resources) shall be determined in accordance with the first applicable 
of the following paragraphs:
    (i) 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 utilization 
facility. In evaluating the acceptability of arm's-length contracts, the 
following factors shall 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;
    (ii) The equivalent value of the least expensive, reasonable 
alternative energy source (fuel). The equivalent value of the least 
expensive, reasonable alternative energy source shall be based on the 
amount of thermal energy that would otherwise be used by the direct 
utilization process in place of the geothermal resource. That amount of 
thermal energy (in Btu's) displaced by the geothermal resource shall be 
determined by the equation

thermal energy displaced =
[GRAPHIC] [TIFF OMITTED] TC15NO91.018


where hin is the enthalpy in Btu's/lb at the utilization 
facility inlet (based on measured inlet temperature), hout is 
the enthalpy in Btu's/lb at the facility outlet (based on measured 
outlet temperature), density is in lbs/cu ft based on inlet temperature, 
the factor 0.133681 (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 of the 
alternative energy source shall 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 shall be determined and approved by BLM; or
    (iii) A value determined by any other reasonable valuation method 
approved by MMS.
    (2) Valuations made pursuant to this paragraph are subject to the 
notification requirements of paragraph (e) of this section.
    (e)(1) Pursuant to subpart H of 30 CFR part 212, the lessee shall 
retain all data relevant to the determination of royalty value, 
particularly where the value is determined pursuant to paragraph (c) or 
(d) of this section. Such data shall be subject to review and audit, and 
MMS will direct a lessee to

[[Page 123]]

use a different value if it determines that the reported value is 
inconsistent with the requirements of these regulations.
    (2) Upon request, lessees shall make available to authorized MMS 
representatives or to other authorized persons any and all contracts for 
the sale or other disposition of the lease production, and any arm's-
length sales and other data for like-quality production sold, purchased, 
or otherwise obtained by the lessee from the field as may be necessary 
to support a value determination.
    (3) A lessee shall notify MMS if it has determined value pursuant to 
paragraph (c) or (d) of this section. The notification shall be by 
letter to the MMS Associate Director for Royalty 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) or (d) 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 
218.302. 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 consistent with this subpart. That determination 
shall remain effective for the period stated therein. After MMS issues 
its determination, the lessee shall make 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 where geothermal 
energy is directly sold.
    (i) The lessee is required to place geothermal resources in 
marketable condition and to deliver geothermal resources to the direct 
utilization facility at no cost to the Federal 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 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 geothermal resource in 
marketable condition or to deliver it to the direct utilization 
facility.
    (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 the 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 shall 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 geothermal resources.
    (k) Notwithstanding any provision in these regulations to the 
contrary, no review, reconciliation, monitoring, or

[[Page 124]]

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 value 
determinations 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 laws 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, 43 CFR part 2.

[56 FR 57276, Nov. 8, 1991; 57 FR 12376, Apr. 9, 1992]



Sec. 206.356  Valuation standards for byproducts.

    (a) The value of geothermal byproducts, including commercially 
demineralized water, shall be determined pursuant to this section, less 
applicable byproducts transportation allowances determined pursuant to 
Secs. 206.357 and 206.358 of this subpart.
    (b)(1)(i) The value of byproducts that are sold pursuant to an 
arm's-length contract shall be the gross proceeds accruing to the 
lessee, except as provided in paragraphs (b)(1)(ii) and (b)(1)(iii) 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.
    (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 byproducts. 
If the contract does not reflect the total consideration, MMS may 
require that the byproducts 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 any additional 
consideration received .
    (iii) 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, MMS shall require that the byproduct 
production be valued pursuant to paragraph (c) of this section and in 
accordance with the notification requirements of paragraph (d) of this 
section. If 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 byproduct value.
    (2) The MMS may require a lessee to certify that the provisions in 
its arm's-length contract include all of the consideration to be paid by 
the buyer, either directly or indirectly, for the byproduct.
    (c) The value of byproducts that are sold pursuant to a non-arm's-
length contract or that are utilized by the lessee (no sales), except 
demineralized water used for the benefit of the lease pursuant to 
paragraph (b)(2) of Sec. 202.351 of this subpart, shall be determined in 
accordance with the first applicable of the following paragraphs:
    (1) The gross proceeds accruing to the lessee pursuant to a sale 
under its non arm's-length contract (or other disposition by other than 
an arm's-length contract), provided that those gross proceeds are not 
less than the gross proceeds derived from or paid under the lowest-
priced available comparable arm's-length contract for sales, purchases, 
or other dispositions of like-quality byproducts in the field or, if 
necessary to obtain a representative sample, from the same area (the 
``minimum value''). If the gross proceeds under the lessee's non-arm's-
length contract are less than the ``minimum value'' under available 
comparable arms length contracts, or if there are no available 
comparable arm's-length contracts, value will be determined by the 
weighted average of the gross proceeds established under arm's-length 
contracts for the sale of like-quality

[[Page 125]]

products in the field or, if necessary to obtain a representative 
sample, from the same area. Available contracts will mean contracts in 
the possession of the lessee, the lessee's affiliate, or MMS. In 
evaluating the comparability of arm's-length contracts for the purposes 
of these regulations, the following factors shall be considered: Field 
or area, price, time of execution, duration, terms, quality of the 
byproduct, volume, market or markets served, and other factors that may 
be appropriate to reflect the value of the byproduct;
    (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) A netback method or any other reasonable method used to 
determine value.
    (d)(1) Pursuant to subpart H of 30 CFR part 212, the lessee shall 
retain all data relevant to the determination of royalty value, 
particularly where the value is determined pursuant to paragraph (c) of 
this section. 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) Upon request, lessees shall make available to authorized MMS 
representatives or to other authorized persons any and all contracts 
and/or invoices for the sale or other disposition of the byproducts, and 
any arm's-length sales and other data for like-quality production sold, 
purchased, or otherwise obtained by the lessee from the field or other 
area as may be necessary to support a value determination.
    (3) A lessee shall notify MMS if it has determined value pursuant to 
paragraph (c) of this section. The notification shall be by letter to 
the MMS Associate Director for Royalty 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) of this section, and each time there is a change in a 
method under paragraph (c) of this section.
    (e) 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 
218.302. 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. In making a value determination, MMS may use any of 
the valuation criteria consistent with 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 (e) of this section.
    (g) Notwithstanding any other provisions of the section, under no 
circumstances shall the value of byproducts for royalty purposes be less 
than the gross proceeds accruing to the lessee, less applicable 
byproduct transportation allowances determined pursuant to Secs. 206.357 
and 206.358 of this subpart.
    (h) The lessee is required to place the byproducts in marketable 
condition at no cost to the Federal Government. 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 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 byproducts in marketable 
condition.

[[Page 126]]

    (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 the contract, and may be retroactively applied to value 
byproducts, for royalty purposes, for a period not to exceed 2 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 byproducts.
    (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 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 byproduct transportation allowances pursuant to 
Secs. 206.357 and 206.358 of this subpart, is exempted from disclosure 
by the Freedom of Information Act, 5 U.S.C. 552. Any data specified by 
the act to be privileged, confidential, or otherwise exempt shall be 
maintained in a confidential manner in accordance with applicable laws 
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, 43 CFR part 2.



Sec. 206.357  Byproduct transportation allowances--general.

    (a) Where the value of byproducts has been determined at a point off 
the geothermal lease, unit, or participating area, MMS shall allow a 
deduction in determining value, for royalty purposes, for the lessee's 
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 utilization 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. Costs for transporting geothermal fluids 
from the lease to the geothermal utilization facility, whether on or off 
the lease, shall not be included in the transportation allowance.
    (b) Under no circumstances shall the byproduct transportation 
allowance authorized by paragraph (a) of this section reduce the value 
of the byproducts under any selling arrangement to zero.
    (c)(1) When byproducts are transported from a lease, unit, 
participating area, or geothermal utilization facility to a byproduct 
recovery facility, the lessee is not required to allocate transportation 
costs between the quantity of marketable byproducts and the rejected 
waste material. The byproduct transportation allowance shall be 
authorized for the total production that is transported. Byproduct 
transportation allowances shall be expressed as a cost per unit of 
marketable byproducts transported.
    (2) For byproducts that are extracted on the lease, unit, or 
participating area, or at the geothermal utilization facility, the 
byproduct transportation allowance shall be authorized for the total 
production that is transported to a point of sale off the lease, unit, 
or participating area. Byproduct transportation allowances shall be 
expressed as a cost per unit of byproduct transported.

[[Page 127]]

    (3) Transportation costs shall be authorized as allowances only when 
the transported byproduct is sold, delivered, or otherwise utilized by 
the lessee and royalties are reported and paid.
    (d) Byproduct transportation allowances are subject to monitoring, 
review, and audit. If, after a review and/or audit, MMS determines that 
a lessee has improperly determined a byproduct transportation allowance 
authorized by this section, then the lessee shall pay any additional 
royalties plus interest determined in accordance with 30 CFR 218.302, or 
shall be entitled to a credit without interest.
    (e) If byproducts produced from Federal and non-Federal leases are 
commingled for transportation, lessees shall not disproportionately 
allocate transportation costs to Federal lease production.
    (f) Upon request, the lessee shall make available to authorized MMS 
representatives or to other authorized persons all transportation 
contracts and all other information as may be necessary to support a 
byproduct transportation allowance.
    (g) Byproduct transportation allowances are to be reported as 
separate lines on Form MMS-2014.



Sec. 206.358  Determination of byproduct 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 byproducts under that contract, subject to 
monitoring, review, audit, and possible future adjustments. The MMS's 
prior approval is not required before a lessee may deduct costs incurred 
under an arm's-length transportation contract.
    (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, MMS may require that the byproduct 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 byproduct 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, MMS shall require that the 
byproduct 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 established on a dollars-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 transportation contract or has no contract, including those 
situations where the lessee performs transportation services for itself, 
the byproduct transportation allowance shall be based upon the lessee's 
reasonable actual costs. All byproduct 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 byproduct transportation allowances is not required for non-
arm's-length or no-contract situations.
    (2) The byproduct 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 capital investment 
in the transportation system

[[Page 128]]

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 assets, including costs of delivery and 
installation of capital equipment, that are an integral part of the 
transportation system. A return on capital invested in the purchase of 
real estate to locate the byproduct transportation facilities may be 
allowed provided that the lessee demonstrates the necessity for such 
purchase, the purchased land is not on a Federal geothermal lease, and 
MMS approves the deduction; the rate of return shall be the same rate 
determined in paragraph (b)(2)(v) of this section.
    (i) Allowable operating expenses include operations supervision and 
engineering, operations labor, fuel, utilities, materials, ad valorem 
property taxes, rent, supplies, and any other allocable and attributable 
operating expenses that 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 that 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) To compute costs associated with capital investment, 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 transportation 
system, the lessee may not later elect to change to the other 
alternative without MMS approval.
    (A) To compute depreciation, the lessee must use a straight-line 
depreciation method based on, as appropriate, either the life of 
equipment or the life of the geothermal project that the transportation 
system services. After an election is made, the lessee may not change 
methods. 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. The rate of return used to compute the return on undepreciated 
capital investment shall be determined pursuant to paragraph (b)(2)(v) 
of this section.
    (B) To compute a return on capital investment, the allowed cost 
shall be the amount equal to the allowable 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.
    (v) The rate of return shall be Standard and Poor's industrial BBB 
bond rate. 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 
annual 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.

Subpart I--OCS Sulfur [Reserved]



                         Subpart J--Indian Coal

    Source: 61 FR 5481, Feb. 12, 1996, unless otherwise noted.



Sec. 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.

[[Page 129]]

    (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.



Sec. 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

[[Page 130]]

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.
    Selling arrangement means the individual contractual arrangements 
under which sales or dispositions of coal are made to a purchaser.
    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]



Sec. 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

[[Page 131]]

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.



Sec. 206.453  Quality and quantity measurement standards for reporting and paying royalties.

    (a) For leases subject to Sec. 206.456 of this subpart, the quality 
of coal on which royalty is due shall be reported on the basis of 
percent sulfur, percent ash, and number of British thermal units (Btu) 
per pound of coal. Coal quality determinations shall be made at 
intervals prescribed in the lessee's sales contract. If there is no 
contract, or if the contract does not specify the intervals of coal 
quality determination, the lessee shall propose a quality test schedule 
to MMS. In no case, however, shall quality tests be performed less than 
quarterly using standard industry-recognized testing methods. Coal 
quality information shall be reported on the appropriate forms required 
under 30 CFR part 216.
    (b) 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 shall 
be reported on appropriate forms required under 30 CFR part 216 and on 
the Report of Sales and Royalty Remittance, Form MMS-2014, as required 
under 30 CFR part 210.



Sec. 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 Sec. 206.455(d) of this subpart.



Sec. 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 Sec. 206.456 of this subpart, and royalties shall be paid 
at the royalty rate specified in the readjusted lease.



Sec. 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,

[[Page 132]]

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 Secs. 206.457 through 
206.461 of this subpart, or any allowance authorized by Sec. 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

[[Page 133]]

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 Royalty 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-2014 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 Secs. 206.457 through 
206.461 and Sec. 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

[[Page 134]]

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 Secs. 206.457 through 206.461 and Sec. 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.



Sec. 206.457  Washing allowances--general.

    (a) For ad valorem leases subject to Sec. 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 
Sec. 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]



Sec. 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.

[[Page 135]]

    (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-

[[Page 136]]

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-2014, Report of Sales and Royalty Remittance. A Form MMS-4292 
received by the end of the month that the Form MMS-2014 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-2014, Report of Sales and Royalty Remittance. A Form MMS-4292 
received by the end of the month that the Form MMS-2014 is due shall be 
considered to be timely received. The initial reporting may be based on 
estimated costs.

[[Page 137]]

    (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-2014, 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-
2014 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-2014 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-2014 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.

[[Page 138]]



Sec. 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.



Sec. 206.460  Transportation allowances--general.

    (a) For ad valorem leases subject to Sec. 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]



Sec. 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

[[Page 139]]

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

[[Page 140]]

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-2014, Reports of Sales and Royalty Remittance.
    (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

[[Page 141]]

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-2014, Report of Sales and Royalty 
Remittance. 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-2014, 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-2014 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.

[[Page 142]]

    (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-2014 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-2014 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]



Sec. 206.462  Contract submission.

    (a) The lessee and other payors shall submit to MMS, upon request, 
contracts for the sale of coal from ad valorem leases subject to this 
subpart. MMS must receive the contracts within a reasonable period of 
time, as specified by MMS. Lessees shall include as part of the 
submittal requirements any contracts, agreements, contract amendments, 
or other documents that affect the gross proceeds received for the sale 
of coal, as well as any other information regarding any consideration 
received for the sale or disposition of coal that is not included in 
such contracts. At the time of its contract submittals, MMS may require 
the lessee to certify in writing that it has provided all documents and 
information that reflect the total consideration provided by purchasers 
of coal from ad valorem leases subject to this subpart. Information 
requested under this section may include contracts for both ad valorem 
and cents-per-ton leases and shall be available in the lessee's offices 
during normal business hours or provided to MMS at such time and in such 
manner as may be requested by authorized Department of the Interior 
personnel. Any oral sales arrangement negotiated by the lessee must be 
placed in a written form and be retained by the lessee. Nothing in this 
section shall be construed to limit the authority of MMS to obtain or 
have access to information pursuant to 30 CFR part 212.
    (b) Lessees and other payors shall designate, for each contract 
submitted pursuant to this section, whether the contract is arm's-length 
or non-arm's-length.
    (c) A lessee's or other payor's determination that its contract is 
arm's-length is subject to future audit to verify that the contract 
meets the criteria of the arm's-length contract definition in 
Sec. 206.451 of this subpart.
    (d) Information required to be submitted under this section that 
constitutes trade secrets and commercial and financial information that 
is identified as privileged or confidential shall not be available for 
public inspection or made public or disclosed without the consent of the 
lessee or other payor, except as otherwise provided by law or 
regulation.

[61 FR 5481, Feb. 12, 1996, as amended at 64 FR 43289, Aug. 10, 1999]



Sec. 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]



Sec. 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

[[Page 143]]

with Sec. 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 Sec. 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 Sec. 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 
Sec. 206.458(b)(2)(v) of this subpart.

[61 FR 5481, Feb. 12, 1996, as amended 64 FR 43289, Aug. 10, 1999]



PART 207--SALES AGREEMENTS OR CONTRACTS GOVERNING THE DISPOSAL OF LEASE PRODUCTS--Table of Contents




                      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



Sec. 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]



Sec. 207.2  Definitions.

    The definitions in part 206 of this title are applicable to this 
part.

[[Page 144]]



Sec. 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 
Sec. 207.5 of this subpart.



Sec. 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.



Sec. 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]



PART 208--SALE OF FEDERAL ROYALTY OIL--Table of Contents




                      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.

[[Page 145]]

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



Sec. 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).



Sec. 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 Sec. 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

[[Page 146]]

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 Sec. 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.

[[Page 147]]

    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]



Sec. 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]



Sec. 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.
    (4) The MMS will recover the administrative costs of the RIK Program 
through the collection of administrative fees. The fees will consist of 
an initial nonrefundable contract fee for each executed contract and a 
monthly variable charge applied to each lease under contract. The amount 
of the initial contract fee shall be determined prior to a sale and 
published in the ``Notice of Availability of Royalty Oil.'' The initial 
contract fee will be payable in equal installments due at the end of the 
first and second months of the contract. These contract fees will be 
applied against the RIK Program's administrative costs, and the 
remainder of the administrative costs will be recovered through the 
monthly variable charges per lease, which will be billed and payable 
concurrently with the monthly actual billings for royalty oil. The rate 
per lease will be determined by dividing the remaining recoverable 
administrative costs by the total number of leases under contract. The 
rate may change depending upon whether total administrative costs change 
and/or whether the number of leases taken in kind changes

[[Page 148]]

from one month to another. In instances where production from a lease is 
sold on a percentage basis to two or more purchasers, each percentage 
portion of the lease will be considered a separate lease for purposes of 
administrative fee determination.
    (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.



Sec. 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.



Sec. 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

[[Page 149]]

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 
Sec. 208.2 of this part.

[52 FR 41913, Oct. 30, 1987, as amended at 58 FR 64901, Dec. 10, 1993]



Sec. 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]



Sec. 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

[[Page 150]]

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.



Sec. 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.



Sec. 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.

[[Page 151]]

    (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 
Sec. 208.2 of this part for MMS to consider assignment of the royalty 
oil contract.



Sec. 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]



Sec. 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 Sec. 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

[[Page 152]]

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 Sec. 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]



Sec. 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]



Sec. 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.



Sec. 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.



Sec. 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]



Sec. 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.



PART 210--FORMS AND REPORTS--Table of Contents




                      Subpart A--General Provisions

Sec.
210.10  Information collection.
210.20  When is electronic reporting required?
210.21  How do you report electronically?
210.22  What are the exceptions to the electronic reporting 
          requirements?

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

210.50  Required recordkeeping.
210.51  Payor information form.
210.52  Report of sales and royalty remittance.
210.53  Reporting instructions.
210.54  Definitions.
210.55  Special forms or reports.

Subpart C--Federal and Indian Oil [Reserved]

Subpart D--Federal and Indian Gas [Reserved]

[[Page 153]]

                   Subpart E--Solid Minerals, General

210.200  Required recordkeeping.
210.201  Solid minerals payor information form.
210.202  Report of sales and royalty remittance--solid minerals.
210.203  Special forms and reports.
210.204  Reporting instructions.

Subpart F--Coal [Reserved]

Subpart G--Other Solid Minerals [Reserved]

                     Subpart H--Geothermal Resources

210.350  Definitions.
210.351  Required recordkeeping.
210.352  Payor information forms.
210.353  Special forms and reports.
210.354  Monthly report of sales and royalty.
210.355  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



Sec. 210.10  Information collection.

    (a) Forms--This section identifies required MMS Royalty Management 
Program forms for reporting sales and royalties, production information, 
claiming a processing or transportation allowance, or claiming a reward 
for providing original information. The information collection 
requirements associated with the forms identified in this section have 
been approved by OMB under 44 U.S.C. 3501 et seq. The forms, filing 
dates, and approved OMB clearance numbers are summarized below:

------------------------------------------------------------------------
               Form No., name, and filing date                  OMB No.
------------------------------------------------------------------------
MMS-2014--Report of Sales and Royalty Remittance--Due by the   1010-0022
 end of first month following production month for royalty
 payment and for rentals no later than anniversary date of
 the lease..................................................
MMS-3160--Monthly Report of Operations-- Due by the 15th day   1010-0040
 of the second month following the production month.........
MMS-4025--Oil and Gas Payor Information Form-- Due 30 days     1010-0033
 after issuance of a new lease or change to an existing
 lease......................................................
MMS-4030--Solid Minerals Payor Information Form-- Due 30       1010-0064
 days after issuance of a new lease or change to an existing
 account established by an earlier form.....................
MMS-4051--Facility and Measurement Information Form and        1010-0040
 Supplement-- Due at the request of MMS during the initial
 conversion of the facility and measurement device operators
MMS-4053--First Purchaser Report-- Due at the request of MMS   1010-0040
MMS-4054--Oil and Gas Operations Report-- Due by the 15th      1010-0040
 day of the second month following the production month.....
MMS-4055--Gas Analysis Report-- Due by the 15th day of the     1010-0040
 second month following the production month................
MMS-4056--Gas Plant Operations Report-- Due by the 15th day    1010-0040
 of the second month following the production month.........
MMS-4058--Production Allocation Schedule Report-- Due by the   1010-0040
 15th day of the second month following the production month
MMS-4059--Solid Minerals Operation Report-- Due by the 15th    1010-0063
 day of the second month following the production month.....
MMS-4060--Solid Minerals Facility Report-- Due by the 15th     1010-0063
 day of the second month following the production month.....
MMS-4070--Application of the Purchase of Royalty Oil-- Due     1010-0042
 prior to the date of sale in accordance with the
 instructions in the Notice of Availability of Royalty Oil..
MMS-4109--Gas Processing Allowance Summary Report-- Initial    1010-0075
 report due within 3 months following the last day of the
 month for which an allowance is first claimed, unless a
 longer period is approved by MMS...........................
MMS-4110--Oil Transportation Allowance Report-- Initial        1010-0061
 report due within 3 months following the last day of the
 month for which an allowance is first claimed, unless a
 longer period is approved by MMS...........................
MMS-4280--Application for Reward for Original Information--    1010-0076
 Due when a reward is claimed for information provided which
 may lead to the recovery of royalty or other payments owed
 to the United States.......................................
MMS-4292--Coal Washing Allowance Report-- Due prior to or at   1010-0074
 the same time that the allowance is first reported on Form
 MMS-2014 and annually thereafter if the allowance does not
 change.....................................................
MMS-4293--Coal Transportation Allowance Report-- Due prior     1010-0074
 to or at the same time that the allowance is first reported
 on Form MMS-2014 and annually thereafter if the allowance
 does not change............................................
MMS-4295--Gas Transportation Allowance Report-- Initial        1010-0075
 report due within 3 months following the last day of month
 for which an allowance is first claimed unless a longer
 period is approved by MMS..................................
MMS-4377--Stripper Royalty Rate Reduction Notification-- Due   1010-0090
 for each 12-month qualifying period that a reduced royalty
 rate is granted by the Bureau of Land Management...........
------------------------------------------------------------------------


The information required on the forms identified in the table above is 
being collected by the Department of the Interior to meet its 
congressionally mandated accounting and auditing responsibilities 
relating to Federal and Indian mineral royalty management. The purpose 
of the forms and the estimated

[[Page 154]]

public reporting burden associated with each form are described in 
paragraph (c) of this section. With the exception of Forms MMS-4109, 
MMS-4110, MMS-4280, MMS-4292, MMS-4293, and MMS-4295, the forms are 
mandatory. Information on Forms MMS-4109, MMS-4110, MMS-4292, MMS-4293, 
and MMS-4295 is required to receive a benefit. Information required on 
Form MMS-4280 must be provided voluntarily to claim a reward. 
Information collected relative to 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, 30 U.S.C. 1701 et seq. for oil and gas production, and by 30 
U.S.C. 189, 30 U.S.C. 359, and 30 U.S.C. 396d for solid mineral 
production.
    (b) MMS mailing addresses--This paragraph identifies the MMS 
address(es) to be used for requesting forms and/or for mailing completed 
forms to MMS.
    (1) Requests for Forms MMS-2014 or MMS-4070 should be addressed to 
the Minerals Management Service, Royalty Management Program, P.O. Box 
5760, Denver, Colorado 80217-5760. The completed Form MMS-2014 should be 
mailed to the Minerals Management Service, Royalty Management Program, 
P.O. Box 5810, Denver, Colorado 80217-5810. The address to which a 
completed Form MMS-4070 should be mailed will be identified in a Federal 
Register Notice of Availability of Royalty Oil. (See 30 CFR 208.5.)
    (2) Requests for Forms MMS-4025 or MMS-4030 should be addressed to 
the Minerals Management Service, Royalty Management Program, P.O. Box 
5760, Denver, Colorado 80217-5760. The completed forms should be mailed 
to the same address.
    (3) Requests for Forms MMS-3160, MMS-4051, MMS-4052, MMS-4053, MMS-
4054, MMS-4055, MMS-4056, MMS-4057, MMS-4058, MMS-4059, MMS-4060, or 
MMS-4061 should be addressed to the Minerals Management Service, Royalty 
Management Program, P.O. Box 17110, Denver, Colorado 80217-0110. The 
completed forms should be mailed to the same address.
    (4) Requests for processing or transportation allowance forms (Forms 
MMS-4109, MMS-4110, MMS-4292, MMS-4293, or MMS-4295) should be addressed 
to the Minerals Management Service, Royalty Management Program, P.O. Box 
25165, Denver, Colorado 80225-0165. The completed allowance forms should 
be mailed to the Minerals Management Service, Royalty Management 
Program, P.O. Box 5200, Denver, Colorado 80217-5200.
    (5) Requests for Form MMS-4280 should be addressed to the Minerals 
Management Service, Royalty Management Program, P.O. Box 25165, Denver, 
Colorado 80225-0165. The completed form should be mailed to the same 
address. (See 30 CFR 218.57(b)).
    (6) Reports delivered to MMS by special couriers or overnight mail 
shall be addressed as follows: Minerals Management Service, Royalty 
Management Program, Building 85, Denver Federal Center, room A-212, 
Denver, Colorado 80225.
    (c) Purpose of forms and estimated public reporting burden--This 
paragraph describes the purpose of the information being collected and 
the estimated public reporting burden associated with the OMB approved 
forms identified in paragraph (a) of this section.
    (1) MMS-2014--Used monthly to report lease-related transactions 
essential for royalty management to determine the correct royalty amount 
due, reconcile or audit data, and distribute payments to appropriate 
accounts. Public reporting burden for paper submission is estimated to 
average 7 minutes to complete each line item on the form, including the 
time necessary to assemble data, calculate value and royalty, and enter 
data on the form. Companies reporting electronically may average 2 
minutes to complete each line item on the form. Comments submitted 
relative to this information collection should reference the information 
collection titled Report of Sales and Royalty Remittance, OMB Control 
Number 1010-0022.
    (2) MMS-3160--Used by onshore oil and gas lease operators to report 
monthly oil and gas production to MMS. Public reporting burden for paper 
submission is estimated to average 15 minutes per form, including the 
time necessary to assemble data, ensure that production and disposition 
numbers are accurate, and enter data

[[Page 155]]

on the form. Companies reporting electronically may average 7.5 minutes 
per month to complete the form. Comments submitted relative to this 
information collection should reference the information collection 
titled PAAS Oil and Gas Reports, OMB Control Number 1010-0040.
    (3) MMS-4025--This form is used to establish a data base of payor 
accounts for oil and gas leases on Federal or Indian lands, reporting 
changes in payor accounts, and notifying MMS of the products on which 
royalties will be paid. Public reporting burden is estimated to average 
30 minutes per form, including time spent reading instructions, 
completing, and mailing the form. Comments submitted relative to this 
information collection should reference Paperwork Reduction Project 
1010-0033.
    (4) MMS-4030--This form is used to establish a data base of payor 
accounts for solid mineral leases on Federal or Indian lands, reporting 
any changes to the accounts, and identifying the type of mine and 
product produced. Public reporting burden is estimated to average 30 
minutes per form, including time spent reading instructions, completing, 
and mailing the form. Comments submitted relative to this information 
collection should reference Paperwork Reduction Project 1010-0064.
    (5) MMS-4051--Used to establish a reference data base identifying 
the facilities where oil and gas production is stored or processed and 
the metering points where production is measured for sale or transfer. 
Public reporting burden is estimated to average 30 minutes per form for 
facility operators to review and update the data base. Comments 
submitted relative to this information collection should reference 
Paperwork Reduction Project 1010-0040.
    (6) MMS-4053--Designed as an audit tool to be used to confirm sales 
data. Public reporting burden is estimated to average 30 minutes per 
form, including time spent reading instructions, completing, and mailing 
the form. Comments submitted relative to this information collection 
should reference Paperwork Reduction Project 1010-0040.
    (7) MMS-4054--This three-part form identifies all oil and gas lease 
production from Federal and Indian lands. MMS uses information from this 
form to track oil and gas from the point of production to the point of 
first sale or other disposition. Respondents will generally not use all 
three parts of the form. Public reporting burden for paper submission is 
estimated to average 30 minutes per month, including the time necessary 
to assemble data, ensure that production and disposition numbers are 
accurate, and enter data on the form. Companies reporting electronically 
may average 15 minutes per month to complete the form. Comments 
submitted relative to this information collection should reference the 
information collection titled PAAS Oil and Gas Reports, OMB Control 
Number 1010-0040.
    (8) MMS-4055--This report identifies the separate components of 
natural gas production. It is submitted quarterly or semiannually by 
lease operators when gas production is processed before royalty value 
has been determined. Public reporting burden is estimated to average 15 
minutes per form including time required gathering data, completing, and 
mailing the form. Comments submitted relative to this information 
collection should reference Paperwork Reduction Project 1010-0040.
    (9) MMS-4056--Submitted monthly by gas plant operators to identify 
components and disposition of natural gas from Federal and Indian 
leases. Public reporting burden is estimated to average 30 minutes per 
form, including time required gathering data, completing, and mailing 
the form. Comments submitted relative to this information collection 
should reference Paperwork Reduction Project 1010-0040.
    (10) MMS-4058--Submitted monthly by operators of the facilities and 
measurement points where production from a Federal or Indian lease is 
commingled with production from other sources before it is measured for 
royalty determination. The data reported is used to determine whether 
sales reported by lessees are reasonable. Public reporting burden is 
estimated to average 15 minutes per form, including time required 
gathering data, completing, and mailing the form. Comments submitted 
relative to this information collection should reference Paperwork 
Reduction Project 1010-0040.

[[Page 156]]

    (11) MMS-4059--This form consists of parts A and B. It is submitted 
by all operators of Federal or Indian solid mineral leases on a schedule 
established on the lease. Public reporting burden is estimated to range 
from 30 minutes per form for the majority of operators who submit only 
part A to report production and disposition of raw materials, to 1.25 
hours for operators submitting both parts A and B to report sales of 
mine production from a facility beyond the mine site. Comments submitted 
relative to this information collection should reference Paperwork 
Reduction Project 1010-0063.
    (12) MMS-4060--Submitted by operators of secondary processing or 
remote storage facilities that handle solid mineral production on which 
royalties have not been determined. The form is usually submitted 
monthly and requires 1 to 2 hours to complete depending on the 
processes, inventory, and production disposition to be reported. 
Comments submitted relative to this information collection should 
reference Paperwork Reduction Project 1010-0063.
    (13) MMS-4070--After publication in the Federal Register of a Notice 
of Availability of Royalty Oil, refiners interested in the purchase of 
royalty oil should submit their applications using this form. The 
information collected is used by MMS to determine if the applicant meets 
eligibility requirements to contract to purchase the oil. Public 
reporting burden is estimated to average 1 hour per form, including time 
required gathering data, completing, and mailing the form. Comments 
submitted relative to this information collection should reference 
Paperwork Reduction Project 1010-0042.
    (14) MMS-4109--Used to claim an allowance for the reasonable, actual 
costs of removing hydrocarbon and nonhydrocarbon elements or compounds 
from the gas streams. Public reporting burden varies depending on the 
type of contract involved. Under an arm's-length contract, burden is 
estimated to average 1 hour for the submission of page 1 and schedule 1 
of the form requiring the lessee's name and address, payor code, plant 
name, accounting identification number, product code, and selling 
arrangement. Nonarm's-length contract claims require completion of all 
pages of the form including calculations of allowable operating and 
maintenance costs, overhead, depreciation, and return on undepreciated 
capital investment. Public reporting burden is estimated to average 10 
hours to complete the entire form. Comments submitted relative to this 
information collection should reference Paperwork Reduction Project 
1010-0075.
    (15) MMS-4110--Used to claim an allowance for expenses incurred by a 
lessee in transporting oil from the lease site to a point remote from 
the lease where value is determined. Public reporting burden varies 
depending on the type of contract involved. Under an arm's-length 
contract, burden is estimated to average 2 hours for the submission of 
page 1 and schedule 1 of the form requiring the lessee's name and 
address, payor code, accounting identification number, product code, and 
selling arrangement. Nonarm's-length contract claims require completion 
of all pages of the form including calculations of allowable operating 
and maintenance costs, overhead, depreciation, and return on 
undepreciated capital investment. Public reporting burden is estimated 
to average 5 hours to complete the entire form. Comments submitted 
relative to this information collection should reference Paperwork 
Reduction Project 1010-0061.
    (16) MMS-4280--This form is used to claim a reward for information 
leading to the recovery of payments owed to the United States from oil 
and gas leases on Federal land or the Outer Continental Shelf. Claimants 
must provide name, address, Social Security number, and a brief 
description of the violation being reported. Public reporting burden is 
estimated to average 30 minutes to complete this form. Comments 
submitted relative to this information collection should reference 
Paperwork Reduction Project 1010-0076.
    (17) MMS-4292--This form is used to claim an allowance for the 
reasonable, actual costs incurred to wash coal. Public reporting burden 
varies depending on the type of contract involved. Under an arm's-length 
contract, burden is estimated to average 1 hour for the submission of 
page 1 of the form requiring the lessee's name and address,

[[Page 157]]

payor code, accounting identification number, product code, and selling 
arrangement. Nonarm's-length contract claims require completion of all 
pages of the form including calculations of allowable operating and 
maintenance costs, overhead, depreciation, and return on undepreciated 
capital investment. Public reporting burden is estimated to average 40 
hours to complete the entire form. Comments submitted relative to this 
information collection should reference Paperwork Reduction Project 
1010-0074.
    (18) MMS-4293--Used 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. Public reporting burden varies depending on the 
type of contract involved. Under an arm's-length contract, burden is 
estimated to average 1 hour for the submission of page 1 of the form 
requiring the lessee's name and address, payor code, accounting 
identification number, product code, and selling arrangement. Nonarm's-
length contract claims require completion of all pages of the form 
including calculations of allowable operating and maintenance costs, 
overhead, depreciation, and return on undepreciated capital investment. 
Public reporting burden is estimated to average 40 hours to complete the 
entire form. Comments submitted relative to this information collection 
should reference Paperwork Reduction Project 1010-0074.
    (19) MMS-4295-- This form is used to claim an allowance for the 
reasonable, actual costs of transporting gas from the lease to the point 
of first sale. Public reporting burden varies depending on the type of 
contract involved. Under an arm's-length contract, burden is estimated 
to average 1 hour for the submission of page 1 and schedule 1 of the 
form requiring the lessee's name and address, payor code, accounting 
identification number, product code, and selling arrangement. Nonarm's-
length contract claims require completion of all pages of the form 
including calculations of allowable operating and maintenance costs, 
overhead, depreciation, and return on undepreciated capital investment. 
Public reporting burden is estimated to average 3 hours to complete the 
entire form. Comments submitted relative to this information collection 
should reference Paperwork Reduction Project 1010-0075.
    (20) MMS-4377-- This form must be submitted by operators of stripper 
oil properties to notify MMS of reduced royalty rates granted by the 
Bureau of Land Management under 43 CFR 3103.4-1 for each 12-month 
qualifying period. Reporting burden is estimated to require an average 
of 30 minutes per form to supply the operator name, lease and agreement 
numbers, calculated and current royalty rate, and the period covered. 
Comments submitted relative to this information collection should 
reference Paperwork Reduction Project 1010-0090.
    (d) Comments on burden estimates.Send comments on the accuracy of 
this burden estimate or suggestions on reducing this burden to the 
Information Collection Clearance Officer, MS 4230, MMS, 1849 C Street, 
NW, Washington, DC 20240 and to the Office of Management and Budget, 
Office of Information and Regulatory Affairs, Attention: Desk Officer 
for the U.S. Department of the Interior, OMB Control Number 1010-
________ (insert appropriate OMB Control Number), Washington, DC 20503. 
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.

[57 FR 41864, Sept. 14, 1992, as amended at 64 FR 38122, July 15, 1999]



Sec. 210.20  When is electronic reporting required?

    (a) You must submit Forms MMS-2014 and MMS-4054 to MMS 
electronically. You must begin reporting electronically according to the 
following timetable unless you qualify for the exceptions to electronic 
reporting listed in Sec. 210.22:

------------------------------------------------------------------------
                                             Then, you must submit that
   If you report the following number of         form electronically
 lines each month on a required form . . .         beginning . . .
------------------------------------------------------------------------
(1) 6 or more.............................  November 1, 1999.
(2) 4-5...................................  November 1, 2000.
(3) 1-3...................................  November 1, 2001.
------------------------------------------------------------------------

    (b) See Sec. 218.40(c) for the definition of a royalty report line 
on Form MMS-2014 and Sec. 216.40(c) for the definition of

[[Page 158]]

a production report line on Form MMS-4054; and
    (c) For purposes of this part, multiple submissions of the same form 
in one month equals one form.

[64 FR 38122, July 15, 1999]



Sec. 210.21  How do you report electronically?

    (a) You may use any of the following electronic media types, unless 
MMS instructs you differently:
    (1) Electronic Data Interchange (EDI) 1--The inter-
organizational, computer-to-computer exchange of structured information 
in a standard, machine-processable format;
---------------------------------------------------------------------------

    \1\ MMS has developed security measures, authentication procedures, 
and automated acknowledgments for this electronic media type.
---------------------------------------------------------------------------

    (2) Electronic Mail (e-mail) 1--Any communication service 
used to electronically transmit and store messages and attach files. MMS 
has three electronic file options:
    (i) Template--MMS-provided software that generates blank forms on a 
personal computer to assist companies in preparing MMS regulatory 
reports (this option is not available for Form MMS-4054);
    (ii) Comma Separated Values (CSV)--A file format where attribute 
fields are separated by commas; and
    (iii) American Standard Code for Information Interchange (ASCII)--A 
file format of fixed-length records with fixed-length attribute fields;
    (3) Reporter-Prepared Diskette (3\1/2\ inch)--A data storage medium 
used to transmit report data using one of the following file formats:
    (i) Template;
    (ii) CSV; and
    (iii) ASCII;
    (4) Magnetic or Cartridge Tape--A data storage medium used to 
transmit report data in an ASCII file format.
    (b) MMS prefers that you use the media types in the order presented 
in paragraph (a) of this section to the extent it is cost effective and 
practical. As technology changes, MMS will consider other media types 
and the order of MMS preference may change. Refer to our electronic 
commerce brochure for the most current reporting options. You can 
receive a copy of our brochure by calling your MMS representative or by 
accessing our Internet site at www.rmp.mms.gov.
    (c) Before you may begin reporting electronically:
    (1) You must submit an electronic sample of your report for MMS 
approval using the MMS-supplied electronic reporting guidelines;
    (2) MMS must notify you that your sample report has been approved;
    (3) MMS must assign you a sender identification number and security 
code for any EDI transmissions; and
    (4) MMS must assign you an originating address and compression 
software password for any e-mail transmissions.

[64 FR 38123, July 15, 1999]



Sec. 210.22  What are the exceptions to the electronic reporting requirements?

    MMS will allow the following grace periods and exceptions to the 
electronic reporting requirements in Sec. 210.20:
    (a) If you become a new MMS reporter after any of the dates you are 
required to submit electronic reports under Sec. 210.20(a), you have 3 
months from the day your first report is due to begin reporting 
electronically;
    (b) If you exceed the maximum number of lines you are allowed to 
report on paper under Sec. 210.20(a), you have 3 months from the last 
day of the month in which you exceeded the line limit to begin reporting 
electronically;
    (c) You are not required to report electronically if you report only 
rent, minimum royalty, or other annual obligations on the Form MMS-2014; 
and
    (d) You are not required to report electronically if you are a small 
business as defined by the U.S. Small Business Administration, and you 
have no computer, no resources to purchase a computer or contract with 
an electronic reporting service, nor access to a computer at a local 
library or other public facility.

[64 FR 38123, July 15, 1999]

[[Page 159]]



              Subpart B--Oil, Gas, and OCS Sulfur--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.



Sec. 210.50  Required recordkeeping.

    Information required by the MMS shall be filed using the forms 
prescribed in this subpart, which are available from MMS. Records may be 
maintained in microfilm, microfiche, or other recorded media that is 
easily reproducible and readable.



Sec. 210.51  Payor information form.

    The Payor Information Form (Form MMS-4025) must be filed for each 
Federal or Indian lease on which royalties are paid. Where specifically 
determined by MMS, Form MMS-4025 is also required for all Federal leases 
on which rent is due. The completed form must be filed by the party who 
is making the rent or royalty payment (payor) for each revenue source. 
Form MMS-4025 must be filed no later than 30 days after issuance of a 
new lease or a modification to an existing lease which changes the 
paying responsibility on the lease.



Sec. 210.52  Report of sales and royalty remittance.

    (a) You must submit a completed Form MMS-2014 (Report of Sales and 
Royalty Remittance) to MMS with:
    (1) All royalty payments; and,
    (2) Rents on nonproducing leases, where specified.
    (b) When you submit Form MMS-2014 data electronically, you must not 
submit the form itself.
    (c) Completed Forms MMS-2014 for royalty payments are due by the end 
of the month following the production month.
    (d) Where applicable, completed Forms MMS-2014 for rental payments 
are due no later than the anniversary date of the lease.
    (e) This section does not prohibit you from making early payments 
voluntarily.

[64 FR 38123, July 15, 1999]



Sec. 210.53  Reporting instructions.

    (a) Specific guidance on how to prepare and submit required 
information collection reports and forms to MMS is contained in an MMS 
``Oil and Gas Payor Handbook,'' a ``Production Accounting and Auditing 
System Reporter Handbook,'' and a ``PAAS Onshore Oil and Gas Reporter 
Handbook.'' The Payor Handbook is available from the Minerals Management 
Service, Royalty Management Program, P.O. Box 5760, Denver, Colorado 
80217-5760. The Reporter Handbooks are available from the Minerals 
Management Service, Royalty Management Program, P.O. Box 17110, Denver, 
Colorado 80217-0110.
    (b) Royalty payors or production reporters should refer to these 
handbooks for specific guidance with respect to oil and gas reporting 
requirements. If additional information is required, the payor or 
reporter should contact the MMS at the above address. The appropriate 
telephone numbers are listed in the handbooks.

[51 FR 45882, Dec. 23, 1986, as amended at 53 FR 16412, May 9, 1988; 57 
FR 41867, Sept. 14, 1992; 58 FR 64902, Dec. 10, 1993]



Sec. 210.54  Definitions.

    Terms used in this subpart shall have the same meaning as in 30 
U.S.C. 1702.

[49 FR 37345, Sept. 21, 1984. Redesignated at 51 FR 45882, Dec. 23, 
1986]



Sec. 210.55  Special forms or reports.

    (a) MMS may require you to submit additional information, forms, or 
reports other than those specifically referred to in this subpart. MMS 
will give you instructions for providing such information or filing such 
reports or forms. MMS will make requests for additional information, 
forms, or reports under this section in conformity with the Paperwork 
Reduction Act of 1995, 44 U.S.C. 3501, and other applicable laws.
    (b) If you file a Form MMS-4025, Payor Information Form (PIF) under 
Sec. 210.51, you must provide the following information to MMS upon 
request for each PIF:
    (1) The AID number for the lease;
    (2) The name, address, Taxpayer Identification Number (TIN), and

[[Page 160]]

phone number of the person for whom you are reporting and paying 
royalties or making other payments under the PIF;
    (3) Whether the person you named in paragraph (b)(2) of this section 
with respect to the lease for which you filed the PIF is a:
    (i) Lessee of record (record title owner);
    (ii) Operating rights owner (working interest owner); or
    (iii) Operator;
    (4) The name, address, and phone number of the individual to contact 
for the person you named in paragraph (b)(2) of this section;
    (5) Your TIN; and
    (6) Whether you are the Designee of the person you named in 
paragraph (b)(2) of this section under 30 U.S.C. 1712(a), and, if so:
    (i) The date your designation became effective; and
    (ii) The date your designation terminates, if applicable; and
    (iii) A copy of the written designation;
    (c) If you have been identified under paragraph (b)(2) of this 
section, you must provide the following information to MMS upon request:
    (1) Confirmation that you are the person identified under paragraph 
(b)(2) of this section;
    (2) Confirmation that the person identified in paragraph (b)(6) of 
this section is your designee; and
    (3) A designation under Sec. 218.52 of this title if the person 
identified in paragraph (b)(6) of this section is not your Designee, and 
if you are not reporting and paying royalties and making other payments 
to MMS.

[62 FR 42066, Aug. 5, 1997]

Subpart C--Federal and Indian Oil [Reserved]

Subpart D--Federal and Indian Gas [Reserved]



                   Subpart E--Solid Minerals, General

    Source: 51 FR 15766, Apr. 28, 1986, unless otherwise noted.



Sec. 210.200  Required recordkeeping.

    Information required by the Minerals Management Service (MMS) shall 
be filed using the forms prescribed in this subpart, copies of which are 
available from MMS. Instructions on the completion of these forms are 
provided in the Payor Handbook--Solid Minerals, also available from MMS. 
Records and supporting data may be maintained in hardcopy, microfilm, 
microfiche, or other recorded media that is readily available and 
readable.



Sec. 210.201  Solid minerals payor information form.

    A Solid Minerals Payor Information Form (Form MMS-4030) must be 
submitted to MMS for each Federal and Indian solid minerals lease on 
which royalties, rentals or minimum royalties are paid. This form does 
not change any requirement for a separate approval, if required, by the 
Department of the Interior. The Form MMS-4030 shall identify the payor 
of rent, minimum royalty, advance royalty and production royalty, and 
identify revenue sources and selling arrangements for all lease 
products. The completed form must be filed by each royalty payor no 
later than 30 days after MMS provides notice that the payor is converted 
to the Auditing and Financial System (AFS). After filing the initial 
form, a new Form MMS-4030 must be filed no later than 30 days after the 
occurrence of any of the following:
    (a) Assignment of all or any part of the lease;
    (b) Adoption of a new mining method;
    (c) Production of a new product;
    (d) A change in a selling arrangement;
    (e) Change in royalty rate;
    (f) Change of payor; or
    (g) Abandonment of a lease.



Sec. 210.202  Report of sales and royalty remittance--solid minerals.

    A completed Report of Sales and Royalty Remittance (Form MMS-2014) 
must accompany all payments to MMS for rents (other than first year) and 
royalties for Federal and Indian solid minerals leases. On leases where 
payment is remitted directly to an Indian tribe or Bureau of Indian 
Affairs office, the payor also must send a completed

[[Page 161]]

form MMS-2014 to MMS for processing in AFS. The Form MMS-2014 shall 
identify the payor and the lease subaccounts, contain production, sales, 
and royalty data, and identify the time period applicable to the data. 
Completed forms are due at the end of the month following the production 
or sales period as applicable. Unless the lease terms specify a 
different royalty payment frequency, all reports and payments are due 
monthly. If the lease terms do specify a different frequency for 
payment, the reporting must coincide with the payment. The Form MMS-2014 
for rental payments is due no later than the rental payment date 
specified in the lease terms.

[51 FR 15766, Apr. 28, 1986, as amended at 57 FR 52720, Nov. 5, 1992]



Sec. 210.203  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, instructions for the filing 
of such forms or reports will be given by MMS. 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.



Sec. 210.204  Reporting instructions.

    (a) Specific guidance on how to prepare and submit required 
information collection reports and forms to MMS is contained in an ``MMS 
Payor Handbook--Solid Minerals'' and a ``Production Accounting and 
Auditing System Reporter Handbook.'' The Payor Handbook is available 
from the Minerals Management Service, Royalty Management Program, P.O. 
Box 5760, Denver, Colorado 80217-5760. The Reporter Handbook is 
available from the Minerals Management Service, Royalty Management 
Program, P.O. Box 17110, Denver, Colorado 80217-0110.
    (b) Royalty payors or production reporters should refer to these 
handbooks for specific guidance with respect to solid minerals reporting 
requirements. If additional information is required, the payor or 
reporter should contact the MMS at the above address. The appropriate 
telephone numbers are listed in the handbooks.

[51 FR 45883, Dec. 23, 1986, as amended at 57 FR 41867, Sept. 14, 1992; 
58 FR 64902, Dec. 10, 1993]

Subpart F--Coal [Reserved]

Subpart G--Other Solid Minerals [Reserved]



                     Subpart H--Geothermal Resources

    Source: 56 FR 57286, Nov. 8, 1991, unless otherwise noted.



Sec. 210.350  Definitions.

    Terms used in this subpart shall have the same meaning as in 30 CFR 
206.351.



Sec. 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.



Sec. 210.352  Payor information forms.

    The Payor Information Form (Form MMS-4025) must be filed for each 
Federal lease on which geothermal royalties (including byproduct 
royalties) are paid. Where specifically determined by MMS, Form MMS-4025 
is also required for all Federal leases on which rent is due. The 
completed form must be filed by the party who is making the rent or 
royalty payment (payor) for each revenue source. Form MMS-4025 must be 
filed no later than 30 days after issuance of a new lease or a 
modification to an existing lease that changes the paying responsibility 
on the lease. The Form MMS-4025 shall identify the payor of production 
royalty, and identify revenue sources and selling arrangements for all 
leased geothermal resources (including byproducts). After filing the 
initial form, a new Form MMS-4025 must be filed no later than 30 days 
after the occurrence of any of the following:
    (a) Assignment of all or any part of the lease;

[[Page 162]]

    (b) Production of new product;
    (c) A change in a selling arrangement;
    (d) Change in royalty rate;
    (e) Change of payor; or
    (f) Abandonment of a lease.



Sec. 210.353  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.



Sec. 210.354  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.



Sec. 210.355  Reporting instructions.

    (a) Specific guidance on how to prepare and submit required 
information collection reports and forms to MMS is contained in an MMS 
Oil and Gas Payor Handbook which is available from the Minerals 
Management Service, Royalty Management Program, P.O. Box 5760, Denver, 
Colorado 80217-5760.
    (b) Royalty payors should refer to this handbook for specific 
guidance with respect to geothermal resources reporting requirements. If 
additional information is required, the payor should contact the MMS at 
the above address. The appropriate telephone numbers are listed in the 
handbook.

[56 FR 57286, Nov. 8, 1991, as amended at 58 FR 64902, Dec. 10, 1993]

Subpart I--OCS Sulfur [Reserved]



PART 212--RECORDS AND FILES MAINTENANCE--Table of Contents




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.; 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 [Reserved]



              Subpart B--Oil, Gas, and OCS Sulphur--General



Sec. 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

[[Page 163]]

written notice of the obligation to maintain records.

[49 FR 37345, Sept. 21, 1984]



Sec. 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) for use in its 
Auditing and Financial System (AFS) and Production Accounting and 
Auditing System (PAAS).
    (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]



Sec. 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



Sec. 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]

[[Page 164]]



                     Subpart H--Geothermal Resources

    Source: 56 FR 57286, Nov. 8, 1991, unless otherwise noted.



Sec. 212.350  Definitions.

    Terms used in this subpart shall have the same meaning as in 30 CFR 
206.351.



Sec. 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 for 
use in its AFS, or in its Production Accounting and Auditing System.
    (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 Royalty 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.

Subpart I--OCS Sulfur [Reserved]

         PART 215--ACCOUNTING AND AUDITING STANDARDS [RESERVED]



PART 216--PRODUCTION ACCOUNTING--Table of Contents




                      Subpart A--General Provisions

Sec.
216.1  Purpose.
216.2  Scope.
216.6  Definitions.
216.10  Information collection.
216.11  Electronic reporting.
216.15  Reporting instructions.
216.16  Where to report.
216.20  Applicability.
216.21  General obligations of the reporter.
216.25  Confidentiality.
216.30  Special forms and reports.
216.40  Assessments for incorrect or late reports and failure to report.

                     Subpart B--Oil and Gas, General

216.50  Monthly report of operations.
216.51  Facility and Measurement Information Form.
216.52  First Purchaser Report.
216.53  Oil and Gas Operations Report.
216.54  Gas Analysis Report.
216.55  Gas Plant Operations Report.
216.56  Production Allocation Schedule Report.
216.57  Stripper royalty rate reduction notification.

[[Page 165]]

Subpart C--Oil and Gas, Onshore [Reserved]

Subpart D--Oil, Gas, and Sulphur, Offshore [Reserved]

                   Subpart E--Solid Minerals, General

216.200  [Reserved]
216.201  Mine Information Report.
216.202  Facility and Measurement Information Form.
216.203  Solid Minerals Operations Report.
216.204  Solid Minerals Facility Report.

Subpart F--Coal [Reserved]

Subpart G--Other Solid Minerals [Reserved]

Subpart H--Geothermal Resources [Reserved]

Subpart I--Indian Land [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).

    Source: 51 FR 8175, Mar. 7, 1986, unless otherwise noted.



                      Subpart A--General Provisions



Sec. 216.1  Purpose.

    The purpose of this part is to ensure that the Federal Government 
receives proper information regarding energy and mineral resources 
removed from Federal and Indian leases and federally approved 
agreements, including the Outer Continental Shelf (OCS).



Sec. 216.2  Scope.

    This part governs the reporting of oil, gas, and solid minerals 
operations information on Federal and Indian leases or federally-
approved agreements including leases or agreements on the OCS. This part 
also governs the reporting of other operational information associated 
with production from Federal and Indian leases or federally-approved 
agreements when such operations occur prior to the point of sale or 
royalty determination, whichever is applicable. Reporters are required 
to submit certain production reports to MMS as set forth in this part.

[58 FR 45254, Aug. 27, 1993]



Sec. 216.6  Definitions.

    For purposes of this part:
    Agreement means a binding arrangement between two or more parties 
purporting to the act of agreeing or of coming to a mutual arrangement 
that is accepted by all parties to a transaction (e.g., 
communitizations, unitization, gas storage, or compensatory royalty 
agreements.).
    Alaska Native Corporation means a corporation created pursuant to 
the provisions of the Alaska Native Claims Settlement Act (43 U.S.C. 
1601 et seq.).
    Approved mining plan as used in this part means an approved resource 
recovery and protection plan (43 CFR 3480.5) or approved mining plan (43 
CFR 3572.1).
    Associate Director means the Associate Director for Royalty 
Management of the MMS.
    Facility means a structure(s) used to store or process Federal or 
Indian mineral production prior to or at the point of royalty 
determination.
    Federal lease means a lease concerning minerals owned by the United 
States and includes a lease where an Alaska Native Corporation receives 
all or part of the royalties accruing from that lease, and the MMS has 
not waived administration of that lease.
    First purchaser means any entity receiving the lease production in a 
first transfer for value transaction.
    Gas means any fluid, either combustible or noncombustible, which is 
extracted from a reservoir and which has neither independent shape nor 
volume, but tends to expand indefinitely; a substance that exists in a 
gaseous or rarefied state under standard temperature and pressure 
conditions.
    Indian lease means a lease concerning lands or interest in lands of 
an Indian Tribe or an Indian allottee, his heirs or devisees, held in 
trust by the United States or which is subject to Federal restriction 
against alienation, including mineral resources and mineral estates 
reserved to an Indian Tribe or an Indian allottee, his heirs or devisees 
thereto in the conveyance of a surface or non-mineral estate, except 
that such term does not include any lands subject to the provisions of 
section 3 of the Act of June 28, 1906 (34 Stat. 539).

[[Page 166]]

    Lease means any contract, profit-share arrangement, joint venture, 
permit, or other agreement issued or approved by the United States under 
a mineral leasing law that authorizes exploration for, extraction of, or 
removal of oil, gas, or solid minerals--or the land area covered by that 
authorization, whichever is covered by the context.
    Lessee means any person to whom the United States, an Indian Tribe, 
or an Indian allottee, issues a lease, or any person who has been 
assigned an obligation to make royalty or other payments required by the 
lease.
    MMS/RMP means the Royalty Management Program of the Minerals 
Management Service.
    Measurement device means a mechanical or electrical device that is 
used to measure production of oil, gas, or solid minerals for sales, 
transfers, and/or royalty determination.
    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 coal or other solid minerals.
    Mineral Leasing Law means any Federal law administered by the 
Secretary authorizing the disposition under lease of oil, gas, or solid 
minerals.
    Oil means any fluid hydrocarbon substance other than gas which is 
extracted in a fluid state from a reservoir and which exists in a fluid 
state under the existing temperature and pressure conditions of the 
reservoir. Oil includes liquefiable hydrocarbon substances such as drip 
gasoline or other natural condensates recovered in a liquid state from 
gas.
    Operator means any person, including a lessee who has control of, or 
who manages operations on, any oil and gas or solid minerals lease site 
on Federal (including the OCS) or Indian lands. ``Operator'' also means 
any entity engaged in the business of developing, drilling for, 
producing, transporting, purchasing, selling, or processing oil, gas or 
solid minerals and/or which has the responsibility of reporting 
production from a lease or a portion thereof.
    Outer Continental Shelf (OCS) has the same meaning as provided in 
section 2 of the Outer Continental Shelf Lands Act, 43 U.S.C. 1331.
    Person means any individual, firm, corporation, association, 
partnership, consortium or joint venture.
    Production Accounting and Auditing System (PAAS) means an integrated 
system of manual and automated processes for minerals production 
reporting, accounting, and auditing. Based upon production reports 
submitted by reporters, the PAAS will track oil, gas, and solid minerals 
produced from or allocated to Federal and Indian leases, including the 
OCS, from the source of production to the point of disposition with 
emphasis on the point of royalty determination, or point of sale, 
whichever is applicable.
    Raw make means natural gas liquids (NGL's) that are extracted from 
the wet gas stream at a gas plant (e.g., ethane through natural 
gasoline) which sometimes is transferred to a fractionation plant for 
further processing.
    Reporter means any reporting entity required to submit a PAAS report 
or form to the MMS.
    Secretary means the Secretary of the Interior or his/her designee.
    Solid minerals means those minerals including but not limited to 
coal, potash, sodium, phosphate, sulfur, lead, zinc, copper, silica 
sands, sand and gravel, and other minerals under mineral leasing laws 
originating from or allocated to Federal or Indian leases, excluding oil 
or gas, oil shale, and geothermal resources.

[51 FR 8175, Mar. 7, 1986, as amended at 58 FR 45254, Aug. 27, 1993]



Sec. 216.10  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]



Sec. 216.11  Electronic reporting.

    You must submit your Oil and Gas Operations Report, Form MMS-4054, 
in accordance with electronic reporting requirements in 30 CFR part 210.

[64 FR 38123, July 15, 1999]

[[Page 167]]



Sec. 216.15  Reporting instructions.

    (a) Specific guidance on how to prepare and submit required 
information collection reports and forms to MMS is contained in a ``PAAS 
Reporter Handbook'' and a ``Paas Onshore Oil and Gas Reporter 
Handbook.'' The Reporter Handbooks are available from the Minerals 
Management Service, Royalty Management Program, P.O. Box 17110, Denver, 
Colorado 80217-0110.
    (b) Production reporters should refer to these handbooks for 
specific guidance with respect to production reporting requirements. If 
additional information is required, the reporter should contact the MMS 
at the above address. The telephone number is listed in the handbooks.

[53 FR 16412, May 9, 1988, as amended at 57 FR 41867, Sept. 14, 1992; 58 
FR 64903, Dec. 10, 1993]



Sec. 216.16  Where to report.

    (a) All reporting forms listed in this part that are mailed or sent 
by U.S. Postal Service express mail should be mailed to the Mineral 
Management Service, Royalty Management Program, P.O. Box 17110, Denver, 
Colorado 80217-0110.
    (b) Reports delivered to MMS by special couriers or overnight mail, 
except U.S. Postal Service express mail, shall be addressed as follows: 
Minerals Management Service, Royalty Management Program, Building 85, 
Denver Federal Center, Denver, Colorado 80225.
    (c) A report is considered received when it is delivered to MMS at 
the addresses specified in paragraphs (a) and (b) of this section. 
Reports received at the MMS addresses specified in paragraphs (a) and 
(b) of this section after 4 p.m. mountain time are considered received 
the following business day.

[56 FR 20127, May 2, 1991, as amended at 57 FR 41867, Sept. 14, 1992; 58 
FR 64903, Dec. 10, 1993]



Sec. 216.20  Applicability.

    The requirements of this part shall apply to all oil, gas, and solid 
mineral operators reporting information on Federal and Indian leases or 
federally-approved agreements, including leases or agreements on the 
OCS.

[58 FR 45254, Aug. 27, 1994]



Sec. 216.21  General obligations of the reporter.

    The reporter shall submit accurately, completely and timely, 
pursuant to the requirements of this part, all information forms and 
other information required by MMS. Specific guidance on the use of the 
required forms is contained in the Production Accounting and Auditing 
System Reporters Handbook. Copies of the handbook are available from the 
MMS.



Sec. 216.25  Confidentiality.

    (a) Information obtained by MMS pursuant to the rules of this part 
shall be open for public inspection and copying during regular office 
hours upon a written request, pursuant to rules at 43 CFR part 2, except 
that:
    (1) Notwithstanding any other provision of this part, information 
obtained from a reporter under this part relating to a minerals 
agreement approved pursuant to the Indian Mineral Development Act of 
1982, 25 U.S.C. 2101 et seq., the Tribal Leasing Act of 1938 (25 U.S.C. 
396a et seq.), or the Allotted Indian Mineral Development Act of 1909 
(25 U.S.C. 396), shall not be released without the written consent of 
the Indian Tribe(s) or individual Indian(s) who are parties to the 
mineral agreement.
    (2) Information obtained from a reporter pursuant to this part that 
constitutes a trade secret and/or commercial or financial information 
which is privileged or confidential, or other information that may be 
withheld under the Freedom of Information Act (5 U.S.C. 552(b)), such as 
geologic and geophysical data concerning wells, shall be available for 
public inspection in accordance with 43 CFR part 2. When such 
information is related to Indian lands, consent to release the 
information must also be obtained from the cognizant Tribe or allottee.
    (b) If any geologic and/or geophysical data is submitted under this 
part, these shall be made available to the public only in accordance 
with the provisions of 30 CFR 250.3, 250.4 and 252.7, if these relate to 
an offshore lease, and in accordance with 43 CFR 3162.8 if these relate 
to an onshore Federal or Indian lease.

[[Page 168]]



Sec. 216.30  Special forms and reports.

    When special forms or reports other than those referred to in the 
regulations in this part are necessary, instructions for the filing of 
such forms or reports will be provided by the Associate Director. Such 
requests will be made in conformity with the requirements of the 
Paperwork Reduction Act of 1980, and are expected to involve less than 
10 respondents annually.



Sec. 216.40  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.
    (b) An assessment of an amount not to exceed $10 may be charged for 
each incorrectly completed report.
    (c) For purposes of oil and gas reporting under the PAAS, a report 
is defined as each line of production information required on the 
Monthly Report of Operations (Form MMS-3160), Oil and Gas Operations 
Report (Form MMS-4054), Gas Analysis Report (Form MMS-4055), Gas Plant 
Operations Report (Form MMS-4056), and Production Allocation Schedule 
Report (Form MMS-4058).
    (d) For purposes of solid minerals reporting under PAAS, a report is 
defined as each line of production information required on the Solid 
Minerals Operation Report (Form MMS-4059) and Solid Minerals Facility 
Report (Form MMS-4060).
    (e) The MMS will not make assessments for reporting problems which 
are beyond the control of the reporter (e.g., reports received late 
because of bad weather). The reporter shall have the burden of proving 
that a reporting problem was unavoidable.
    (f) An assessment under this section shall not be shared with a 
State, Indian tribe, Indian allottee, or Alaska Native Corporation.
    (g) 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.

[51 FR 8175, Mar. 7, 1986, as amended at 52 FR 27546, July 22, 1987; 53 
FR 16412, May 9, 1988; 58 FR 64903, Dec. 10, 1993; 59 FR 38905, Aug. 1, 
1994]



                     Subpart B--Oil and Gas, General



Sec. 216.50  Monthly report of operations.

    (a) You must submit a Monthly Report of Operations, Form MMS-3160, 
if you operate either an onshore Federal or Indian lease or an onshore 
federally-approved agreement that contains one or more wells that are 
not permanently plugged and abandoned. You may submit Form MMS-3160 
electronically.
    (b) You must submit a Form MMS-3160 for each well for each calendar 
month, beginning with the month in which you complete drilling, unless 
you have only test production from a drilling well or MMS tells you in 
writing to do otherwise.
    (c) MMS must receive your completed Form MMS-3160 according to the 
following table:

------------------------------------------------------------------------
       If you submit your form . . .         We must receive it by . . .
------------------------------------------------------------------------
(1) Electronically........................  The 25th day of the second
                                             month following the month
                                             for which you are
                                             reporting.
(2) Other than electronically.............  The 15th day of the second
                                             month following the month
                                             for which you are
                                             reporting.
------------------------------------------------------------------------

    (d) You must continue reporting until either:
    (1) BLM approves all wells as permanently plugged or abandoned and 
you dispose of all inventory; or
    (2) The lease or agreement is terminated.
    (e) You are not required to submit Form MMS-3160 if:
    (1) You are authorized to submit an Oil and Gas Operations Report, 
Form MMS-4054, instead of a Form MMS-3160; or
    (2) You operate a gas storage agreement. You must report gas storage 
agreements to the appropriate BLM office.
    (f) Specific and detailed guidance on how to prepare and submit the 
required production data on the Form MMS-3160 are contained in the MMS 
PAAS Onshore Oil and Gas Reporter Handbook.See Sec. 216.15 of this part.

[[Page 169]]

    (g)(1) Operators already reporting onshore lease production data to 
MMS in accordance with Sec. 216.53 of this part on the effective date of 
this rule may request to change to the provisions of this section. Any 
request to change to the requirements of this section must be made by 
advance written notice to MMS and have MMS approval.
    (2) An operator who reports production data to MMS for offshore 
leases in accordance with Sec. 216.53 of this part may request to report 
for its onshore leases in accordance with the requirements of that 
section. Any such request must be made by advance written notice to MMS 
and have MMS approval.
    (h)(1) Except where disclosure is required by law, information 
submitted on Form MMS-3160 that MMS classifies as confidential will be 
protected as such by both MMS and BLM for the period of 1 year. 
Operators must petition MMS for each lease or agreement to obtain a 
confidential classification and to extend the classification period 
beyond 1 year.
    (2) Except as provided by statute, information submitted on Form 
MMS-3160 in regard to Federal leases and Indian leases which are part of 
a unit containing non-Indian leases is not considered to be 
confidential.
    (3) Except where disclosure is required by law, all information 
submitted on Form MMS-3160 in regard to Indian leases, other than those 
included in paragraph (d)(2) of this section, will be considered to be 
confidential.
    (4) Except as provided in this subsection, all other information 
will be released.

[53 FR 16412, May 9, 1988, as amended at 58 FR 45254, Aug. 27, 1993; 58 
FR 64903, Dec. 10, 1993; 64 FR 38123, July 15, 1999]



Sec. 216.51  Facility and Measurement Information Form.

    A Facility and Measurement Information Form (Form MMS-4051) must be 
filed for each facility or measurement device which handles production 
from any Federal or Indian lease, or federally-approved agreement, 
through the point of first sale or the point of royalty computation, 
whichever is later. The completed form must be filed by any operator 
(reporting production on a Form MMS-4054) of an onshore Facility 
Measurement Point (FMP) that handles production from any Federal or 
Indian lease or federally-approved agreement prior to, or at the point 
of royalty determination, or any operator who acquires an onshore FMP 
that is currently reporting to the PAAS. The report must be filed no 
later than 30 days after the establishment of a new facility or 
measurement device, or 30 days after a change is made to an existing 
facility or measurement device.

[58 FR 45254, Aug. 27, 1993]



Sec. 216.52  First Purchaser Report.

    The First Purchaser Report (Form MMS-4053) must be filed by first 
purchasers only upon the specific request of MMS.

[51 FR 8175, Mar. 7, 1986. Redesignated at 58 FR 64903, Dec. 10, 1993]



Sec. 216.53  Oil and Gas Operations Report.

    (a) You must file an Oil and Gas Operations Report, Form MMS-4054, 
if you operate one of the following that contains one or more wells that 
are not permanently plugged or abandoned:
    (1) An OCS lease or federally-approved agreement; or
    (2) An onshore Federal or Indian lease or federally-approved 
agreement for which you elected to report on a Form MMS-4054 instead of 
a Form MMS-3160.
    (b) You must submit a Form MMS-4054 for each well for each calendar 
month, beginning with the month in which you complete drilling, unless 
you have only test production from a drilling well or MMS tells you in 
writing to do otherwise.
    (c) MMS must receive your completed Form MMS-4054 according to the 
following table:

------------------------------------------------------------------------
       If you submit your form . . .         We must receive it by . . .
------------------------------------------------------------------------
(1) Electronically........................  The 25th day of the second
                                             month following the month
                                             for which you are
                                             reporting.
(2) Other than electronically.............  The 15th day of the second
                                             month following the month
                                             for which you are
                                             reporting.
------------------------------------------------------------------------


[[Page 170]]

    (d) You must continue reporting until either:
    (1) BLM or MMS approves all wells as permanently plugged or 
abandoned and you dispose of all inventory; or
    (2) The lease or agreement is terminated.

[64 FR 38124, July 15, 1999]



Sec. 216.54  Gas Analysis Report.

    When requested by MMS, any operator must file a Gas Analysis Report 
(GAR) (Form MMS-4055) for each royalty or allocation meter. The form 
must contain accurate and detailed gas analysis information. This 
requirement applies to offshore, onshore, or Indian leases.
    (a) MMS may request a GAR when you sell gas, or transfer gas for 
processing, before the point of royalty computation.
    (b) When MMS first requests this report, the report is due within 30 
days. If MMS requests subsequent reports, they will be due no later than 
45 days after the end of the month covered by the report.

[63 FR 26367, May 12, 1998]



Sec. 216.55  Gas Plant Operations Report.

    (a) You must submit a Gas Plant Operations Report, Form MMS-4056, if 
you operate either:
    (1) A gas plant that processes gas originating from an OCS lease or 
federally-approved agreement before the point of final royalty 
determination; or
    (2) A gas plant that processes gas from an onshore Federal or Indian 
lease or federally-approved agreement before the point of final royalty 
determination, and MMS has asked you to submit a Form MMS-4056.
    (b) You must submit a Form MMS-4056 for each calendar month 
beginning with the month gas processing is initiated.
    (c) MMS must receive your completed Form MMS-4056 according to the 
following table:

------------------------------------------------------------------------
                                              We must receive your Form
  If you submit your Form MMS-4054 . . .          MMS-4056 by . . .
------------------------------------------------------------------------
(1) Electronically........................  The 25th day of the second
                                             month following the month
                                             for which you are
                                             reporting.
(2) Other than electronically.............  The 15th day of the second
                                             month following the month
                                             for which you are
                                             reporting.
------------------------------------------------------------------------

    (d) Your report must show 100 percent of the gas.
    (e) You are not required to file a Form MMS-4056 if:
    (1) Your plant has not processed gas that originated from a Federal 
onshore, OCS, or Indian lease, or federally-approved agreement before 
the point of final royalty determination for 6 months; and
    (2) You notified MMS in writing within 30 days after the end of the 
6-month period.
    (f) You must file a Form MMS-4056 when your plant resumes processing 
gas that originated from a Federal onshore, OCS, or Indian lease, or 
federally-approved agreement before the point of final royalty 
determination.

[64 FR 38124, July 15, 1999]



Sec. 216.56  Production Allocation Schedule Report.

    (a) Any operator of an offshore Facility Measurement Point (FMP) 
handling production from a Federal lease or federally-approved agreement 
that is commingled (with approval) with production from any other source 
prior to measurement for royalty determination must file a Production 
Allocation Schedule Report (Form MMS-4058). This report is not required 
whenever all of the following conditions are met:
    (1) All leases involved are Federal leases;
    (2) All leases have the same fixed royalty rate;
    (3) All leases are operated by the same operator;
    (4) The facility measurement device is operated by the same person 
as the leases/agreements;
    (5) Production has not been previously measured for royalty 
determination; and
    (6) The production is not subsequently commingled and measured for 
royalty determination at an FMP for which Form MMS-4058 is required 
under this part.
    (b) You must submit a Production Allocation Schedule Report, Form

[[Page 171]]

MMS-4058, for each calendar month beginning with the month in which you 
first handle production covered by this section.
    (c) MMS must receive your Form MMS-4058 according to the following 
table:

------------------------------------------------------------------------
                                              We must receive your Form
  If you submit your Form MMS-4054 . . .          MMS-4058 by . . .
------------------------------------------------------------------------
(1) Electronically........................  The 25th day of the second
                                             month following the month
                                             for which you are
                                             reporting.
(2) Other than electronically.............  The 15th day of the second
                                             month following the month
                                             for which you are
                                             reporting.
------------------------------------------------------------------------


[58 FR 45255, Aug. 27, 1993. Redesignated at 58 FR 64903, Dec. 10, 1993, 
as amended at 64 FR 38124, July 15, 1999]



Sec. 216.57  Stripper royalty rate reduction notification.

    In accordance with its regulations at 43 CFR 3103.4-1, titled 
``Waiver, suspension, or reduction of rental, royalty, or minimum 
royalty,'' the Bureau of Land Management (BLM) may grant reduced royalty 
rates to operators of low producing oil leases to encourage continued 
production. Operators who have been granted a reduced royalty rate(s) by 
BLM must submit a Stripper Royalty Rate Reduction Notification (Form 
MMS-4377) to MMS for each 12-month qualifying period that a reduced 
royalty rate(s) is granted.

[58 FR 64903, Dec. 10, 1993]

Subpart C--Oil and Gas, Onshore [Reserved]

Subpart D--Oil, Gas, and Sulfur, Offshore [Reserved]



                   Subpart E--Solid Minerals, General



Sec. 216.200  [Reserved]



Sec. 216.201  Mine Information Report.

    The Mine Information Form (Form MMS-4050) must be filed for each 
mine that includes Federal or Indian leases in its approved mining plan. 
The completed form must be filed by the operator of the mine/lease(s). 
Form MMS-4050 must be filed at the request of the MMS initially during 
the conversion of the mine/lease(s) to the PAAS.



Sec. 216.202  Facility and Measurement Information Form.

    The Facility and Measurement Information Form (Form MMS-4051) must 
be filed for each facility or measurement device which handles solid 
mineral production from any Federal or Indian lease, or federally 
approved agreement, through the point of first sale or the point of 
royalty computation, whichever is applicable. The completed form must be 
filed by the operator of the facility or measurement device. Form MMS-
4051 must be filed initially at the request of the MMS during the 
conversion of facility and measurement device operators to the PAAS. 
Subsequent to conversion, Form MMS-4051 must be filed with MMS/RMP no 
later than 30 days after establishment of a new facility or measurement 
device, or a change to any existing facility or measurement device that 
handles production attributable to any Federal or Indian lease, or 
federally approved agreement, through the point of first sale or royalty 
computation, whichever is applicable.



Sec. 216.203  Solid Minerals Operations Report.

    The Solid Minerals Operation Report (Form MMS-4059) must be 
submitted by all Federal and Indian lease operators of producing mines 
that are part of an approved mine plan. Form MMS-4059 must be filed for 
the same period established for payment for royalties in the lease 
terms, unless a different reporting frequency is established by an MMS 
authorized official, and on or before the 15th day of the second month 
following the period being reported until all the leases within a mine 
are terminated or until omission of the report is authorized by the MMS.



Sec. 216.204  Solid Minerals Facility Report.

    The Solid Minerals Facility Report (Form MMS-4060) must be filed by 
operators of secondary processing facilities that handle production 
attributable to Federal or Indian leases where royalty is determined 
after processing. The report period is monthly, unless a longer period 
is specified in the lease document, or otherwise approved by the MMS. 
The Form MMS-

[[Page 172]]

4060 must be filed on or before the 15th day of the second month 
following the period being reported.

Subpart F--Coal [Reserved]

Subpart G--Other Solid Minerals [Reserved]

Subpart H--Geothermal Resources [Reserved]

Subpart I--Indian Land [Reserved]



PART 217--AUDITS AND INSPECTIONS--Table of Contents




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 [Reserved]

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.



Sec. 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.



Sec. 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.



Sec. 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



Sec. 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 Royalty 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

[[Page 173]]

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 Royalty Management within 30 
days after the completion of each audit. Where such audits are required, 
the Associate Director for Royalty 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]



                     Subpart F--Other Solid Minerals



Sec. 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 [Reserved]

Subpart H--Indian Lands [Reserved]



PART 218--COLLECTION OF ROYALTIES, RENTALS, BONUSES AND OTHER MONIES DUE THE FEDERAL GOVERNMENT--Table of Contents




                      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.
218.57  Providing information and claiming rewards.

                     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  Rentals.
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.

Subpart G--Indian Lands [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.; 31 U.S.C.A. 
3335; 43 U.S.C. 1301 et seq. 1331 et seq., 1801 et seq.



                      Subpart A--General Provisions



Sec. 218.10  Information collection.

    The information collection requirements contained in this part have 
been approved by OMB under 44 U.S.C. 3501

[[Page 174]]

et seq. The forms, filing date, and approved OMB clearance numbers are 
identified in 30 CFR 210.10.

[57 FR 41867, Sept. 14, 1992]



Sec. 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.
    (b) An assessment of an amount not to exceed $10 may be charged for 
each incorrectly completed report.
    (c) For purposes of reports required for the Auditing and Financial 
System (AFS), a report is defined as each line item on a Form MMS-2014. 
The line item consists of the various information, such as Product Code 
or Selling Arrangement Code, relating to each Accounting Identification 
Number (AID).
    (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]



Sec. 218.41  Assessments for failure to submit payment of same amount as Form MMS-2014 or bill document or to provide adequate information.

    (a) An assessment of an amount not to exceed $250 may be charged 
when the amount of a payment submitted by a payor is not equivalent in 
amount to the total of individual line items on the associated Form MMS 
2014 or bill document, unless the difference in amount has been 
authorized by MMS.
    (b) An assessment of an amount not to exceed $250 may be charged for 
each payment submitted by a payor that cannot be automatically applied 
by AFS to the associated Form MMS-2014 or bill document because of 
inadequate or erroneous information submitted by the payor. 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 payor in Block 3a on a Form MMS-2014, or the reuse 
of the same payor assigned document (``3a'') number in a subsequent 
reporting period.
    (2) Absent or incorrect bill document invoice number (to include the 
four character alpha prefix and the eight digit number) or the payor-
assigned 3a number required to be identified by the payor on the 
associated payment document, or the reuse of the same payor assigned 3a 
number in a subsequent reporting period.
    (3) Absent or incorrect name of the administering Bureau of Indian 
Affairs Agency/Area office and 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 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.
    (c) For purposes of this section, the term ``Form MMS-2014'' 
includes submission of reports of royalty information by magnetic media. 
Magnetic media submissions include submissions by magnetic tape, 
magnetic cartridge, or floppy diskette.
    (d) For purposes of this section, a bill document is defined as any 
Bill of Collection (Form DI-1040b) that has been issued by MMS for 
assessments, late-payment interest charges, or other amounts owed.
    (e) For purposes of this section, a payment document is defined as 
one of the payment methods identified in Sec. 218.51(a)(3).
    (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

[[Page 175]]

publish a Notice in the Federal Register of the assessment amount to be 
applied with the effective date.

[58 FR 45438, Aug. 30, 1993]



Sec. 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.



Sec. 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) Payments made on a Bill for Collection (Form DI-1040b) are due 
as specified by the Bill. Bills for Collection will be issued and 
payable as final collection actions.
    (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.



Sec. 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.

[[Page 176]]

    Invoice Document Identification--The MMS-assigned invoice document 
identification (four alpha and eight 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, Royalty Management Program, 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, Royalty Management Program, 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, Royalty Management Program, Building 
85, Denver Federal Center, Room A-212, 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

[[Page 177]]

both your payor code (block 2) and your payor-assigned document number 
(block 3a).
    (2) For invoice payments, including RIK invoice payments, you must 
include both your payor code and invoice document identification (four-
letter prefix and eight-digit number).
    (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 Sec. 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 30 CFR 243.2, ``Suspensions of orders or decisions 
pending appeal.'' 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 30 CFR 241.20 and 241.51 or other applicable 
regulations.

[62 FR 19498, Apr. 22, 1997]



Sec. 218.52  How does a lessee designate a Designee?

    (a) If you are a lessee under 30 U.S.C. 1701(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. Your 
notification for each lease must include the following:
    (1) The AID 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, and the 
percentage of your record title ownership 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;

[[Page 178]]

    (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 provide to MMS in writing before the 
termination:
    (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]



Sec. 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 
``Oil and Gas Payor Handbook.'' See 30 CFR 210.53. 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]



Sec. 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 Sec. 218.42.

[49 FR 37346, Sept. 21, 1984, as amended at 55 FR 37230, Sept. 10, 1990; 
57 FR 62206, Dec. 30, 1992]



Sec. 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 Sec. 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]

[[Page 179]]



Sec. 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]



Sec. 218.57  Providing information and claiming rewards.

    (a) General. (1) If a person has any information that could lead to 
the recovery of royalty or other payments owed to the United States with 
respect to any oil and gas lease on Federal lands or the Outer 
Continental Shelf, such information may be provided to the Minerals 
Management Service (MMS) in accordance with this paragraph. The MMS is 
authorized, under the Federal Oil and Gas Royalty Management Act of 1982 
(FOGRMA), 30 U.S.C. 1723, to pay a reward for information with respect 
to Federal oil and gas leases. Funds must be appropriated before payment 
of any reward. Criteria and procedures covering claims for and payment 
of rewards are provided in paragraphs (b), (c), and (d) of this section.
    (2) If a person has any information he or she believes would be 
valuable to MMS, that person (``informant'') should submit the 
information in writing, in the form of a letter, mailed or delivered in 
person to the Director, Minerals Management Service, Department of the 
Interior, 18th and C Street, NW., Washington, DC 20240, or to the 
Director's designated representative. Although written communications 
are preferred, oral information will be accepted.
    (3) The informant should provide all data he or she has with respect 
to royalty or other payments owed. The information provided should 
include: identification of the alleged debtor; the source of the 
informant's knowledge of royalties or other payments owed; the date, if 
known, of the indebtedness; and any other information that could be used 
to establish indebtedness. All information received by MMS from persons 
providing information will be considered ``highly confidential'' and 
will not be disclosed to any individual except on a ``need to know'' 
basis in the performance of official duties.
    (b) Claim for reward. (1) Any informant who provides information 
that could lead to the recovery of royalty or other payments may file a 
claim for reward unless the person is an officer or employee of the 
United States, an officer or employee of a State or Indian tribe acting 
pursuant to a cooperative agreement or delegation under the FOGRMA, or 
any person acting pursuant to a contract authorized by the FOGRMA.
    (2) A claim for reward is not acceptable if filed on behalf of a 
claimant by his or her agent under power of attorney. However, an agent 
may provide MMS with information for an unidentified informant, to be 
evaluated and used by MMS as it deems appropriate. The informant's 
identity ultimately must be disclosed if the informant intends to file a 
claim for reward so that MMS can report the reward as taxable income to 
the Internal Revenue Service. An executor, administrator, or other legal 
representative of a deceased informant may file a claim on behalf of 
such deceased informant if, prior to his or her death, the informant was 
eligible to file a claim under this section. The representative must 
attach to the claim evidence of authority to file it.
    (3) To file a claim for reward the informant must:
    (i) Notify the Director, MMS, or the person to whom the information 
was reported, that he/she is claiming a reward.
    (ii) Request an ``Application for Reward for Original Information'' 
(Form MMS-4280). This form provides for information to enable MMS to 
determine and pay rewards, to control reward applications, and to report 
a claimant's reward as taxable income to the Internal Revenue Service.
    (iii) File a claim for reward by completing Form MMS-4280, sign it 
with his or her true name, and mail or deliver it in person to the 
Director or to the Director's designated representative. If the 
informant provided the information in person, the claim should include 
the name and title of the person to whom the information was reported 
and the date that it was reported.
    (4) If the informant used an identity other than his or true name 
when the

[[Page 180]]

information was originally reported, the person should attach proof to 
the claim that he or she is the person who gave the information. The MMS 
does not disclose the identity of its informants to unauthorized 
persons.
    (c) Basis for rejection of claims. No reward will be paid to a 
claimant:
    (1) Where the information originally furnished was deemed unworthy 
of initiating an investigation, but at some later date the records of 
the lessee are examined without reference to the information furnished. 
The claim will be rejected on the basis that the information did not 
cause the investigation nor did it, in itself, result in any recovery.
    (2) For information that would have been discovered during the 
normal course of an audit or investigation.
    (3) Unless the informant's true identity is disclosed.
    (4) Until after all of the royalties, penalties, or other payments 
discovered to be owed as a result of information provided are collected 
and no longer subject to dispute.
    (5) Unless funds are appropriated for the payment of rewards.
    (d) Basis for allowance of claims. (1) The value of the information 
furnished in relation to the facts developed by the investigation will 
be taken into account in determining whether a reward shall be paid and, 
if so, the amount thereof. Information must be voluntarily given and 
upon the informant's own initiative to warrant the allowance of a 
reward. Information secured by representatives of MMS from witnesses and 
others in the course of their investigative activities does not 
constitute a basis for reward.
    (2) In determining whether a reward will be allowed and, if so, the 
amount thereof, consideration will be given to any corresponding 
adjustment(s) which will result in potential savings to the lessee for 
other leases owned by the lessee or an affiliate of the lessee. An 
example of such an adjustment is a reduction in royalty payment on a 
different lease as the result of a revised allocation under a 
unitization or communitization agreement or from an offshore pipeline 
system. Rewards otherwise allowable will be reduced or rejected by 
reason of such offsetting adjustments.
    (3) If several claims filed by one informant are considered in one 
recommendation, the reward, if any, may be allowed on one claim and the 
others may be closed by reference.
    (4) Where an informant has provided information and filed a claim 
for reward with respect to royalty reports of one lessee for several 
leases, no reward will be granted with respect to an individual lease 
which has been examined until examination of all leases involved has 
been completed. Because the possibility exists that adjustments made to 
the reports for the open leases may result in offsetting adjustments, no 
reward will be allowed until the overall results of the information are 
evaluated.
    (e) Amount and payment of reward. (1) The Director, MMS will 
determine whether a reward will be paid and, if so, the amount thereof. 
In making this decision, the information provided will be evaluated in 
relation to the facts developed by the resulting investigation. Claims 
for reward will be paid in proportion to the value of information 
furnished voluntarily and on the informant's own initiative with respect 
to recovered royalties or other payments. The amount of reward will be 
determined as follows:
    (i) For specific and responsible information that caused the 
investigation and resulted in recovery, the reward will be 10 percent of 
the first $75,000 recovered, 5 percent of the next $25,000, and 1 
percent of any additional recovery. The total reward cannot exceed 
$100,000.
    (ii) For information that caused the examination and was of value in 
determining royalty or other payments due, although not specific, and 
for information that was a direct factor in recovering royalty or other 
payments, the reward will be 5 percent of the first $75,000 recovered, 
2\1/2\ percent of the next $25,000, and \1/2\ percent of any additional 
recovery. The total reward cannot exceed $100,000.
    (iii) For information that caused the investigation but was of no 
value in determining royalty or other payments due, the reward will be 1 
percent of the first $75,000 recovered and \1/2\ percent of

[[Page 181]]

any additional recovery. The total reward cannot exceed $100,000.
    (2) Rewards will be paid only if moneys are appropriated for that 
purpose. Subject to appropriations, payments will be made as soon as 
possible after collection of the amounts owed by the lessee, and after 
those amounts no longer are subject to dispute by the payor. The reward 
payment to an informant will be net of Federal and State income tax in 
accordance with withholding guidelines of the Internal Revenue Service 
and the applicable State(s).
    (3) A decision by the Director, MMS, either denying a reward or 
establishing the amount of any reward is a final departmental action and 
may not be appealed to the Interior Board of Land Appeals in accordance 
with the provisions of 30 CFR part 290.

(Approved by the Office of Management and Budget under control number 
1010-0076)

[52 FR 24451, July 1, 1987]



                     Subpart C--Oil and Gas, Onshore



Sec. 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]



Sec. 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]



Sec. 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 
Sec. 218.51(f)(1) and (f)(2). 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

[[Page 182]]

which interest is due pursuant to conditions specified in Sec. 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]



Sec. 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 Sec. 219.100 of this chapter, or that is 
held in a suspense account pending resolution of a dispute as specified 
in Sec. 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]



Sec. 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]



Sec. 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



Sec. 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 
Sec. 218.51(f)(1) and (f)(2). 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;

[[Page 183]]

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 Sec. 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]



Sec. 218.151  Rentals.

    (a) Except for leases issued subject to net profit sharing 
provisions, an annual rental shall be due and payable in advance, at the 
rate specified in the oil and gas leases, on the first day of each lease 
year prior to discovery of oil or gas on the lease.
    (b) The owner of any lease created by the segregation of a portion 
of a producing lease which is not subject to net profit sharing 
provisions and on which segregated portion there is no production, 
actual or allocated, 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 lease year following the year in which the 
segregation became effective and prior to a discovery on such segregated 
portion.
    (c) Annual rental paid in any year shall be in addition to, and 
shall not be credited against, any royalties due from production.
    (d) An annual rental on a lease for a mineral other than oil or gas, 
shall be due and payable, in advance, on the first day of each lease 
year prior to discovery in paying quantities, at a rate specified in the 
lease form.
    (e) 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 
segreation 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]



Sec. 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]
Sec. 218.153  [Reserved]



Sec. 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 (a)

[[Page 184]]

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]



Sec. 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 
Sec. 218.51 of this part. 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 checks 
submitted with bids other than the highest valid bid shall be returned 
to respective bidders after bids are opened, recorded, and ranked. 
Return of such checks 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 
Sec. 218.51 (f)(1) and (f)(2).
    (4) Payments received at the MMS addresses after 4 p.m. mountain 
time

[[Page 185]]

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]



Sec. 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



Sec. 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]



Sec. 218.201  Method of payment.

    The payor shall tender all payments in accordance with 30 CFR 
218.51.

[52 FR 23815, June 25, 1987]



Sec. 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(f)(1) 
and (f)(2). Payments received at the specified MMS addresses after 4 
p.m. mountain time are considered received the following business day.
    (c) The interest charge on late payments shall be at the 
underpayment rate established by section 6621(a)(2) of the Internal 
Revenue Code, 26 U.S.C. 6621(a)(2).
    (d) Interest will be charged only on the amount of the payment not 
received by the designated due date. Interest will be charged only for 
the number of days the payment is late.
    (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 Sec. 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; 57 FR 41868, Sept. 14, 1992; 57 FR 62207, Dec. 30, 1992; 59 FR 
14559, Mar. 29, 1994]



Sec. 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-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

[[Page 186]]

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 ``AFS 
Payor Handbook--Solid Minerals.'' See 30 CFR 210.204. 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]



                     Subpart F--Geothermal Resources



Sec. 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]



Sec. 218.301  Method of payment.

    The payor shall tender all payments in accordance with 30 CFR 
218.51.

[52 FR 23815, June 25, 1987]



Sec. 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 Sec. 218.51 
(f)(1) and (f)(2). Payments received at the specified MMS addresses 
after 4 p.m. Mountain Time are considered received the following 
business day.
    (c) The interest charge on late payments shall be at the 
underpayment rate established by section 6621(a)(2) of the Internal 
Revenue Code, 26 U.S.C. 6621(a)(2).
    (d) Interest will be charged only on the amount of the payment not 
received by the designated due date. Interest will be charged only for 
the number of days the payment is late.
    (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 Sec. 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; 57 FR 41868, Sept. 14, 1992; 57 FR 62207, Dec. 30, 1992; 
59 FR 14559, Mar. 29, 1994]

Subpart G--Indian Lands [Reserved]

[[Page 187]]



PART 219--DISTRIBUTION AND DISBURSEMENT OF ROYALTIES, RENTALS, AND BONUSES--Table of Contents




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



Sec. 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.



Sec. 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 Sec. 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.



Sec. 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, Royalty Management Program, P.O. Box 5760, 
Denver, Colorado 80217-5760.

[57 FR 41868, Sept. 14, 1992, as amended at 58 FR 64903, Dec. 10, 1993]



Sec. 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.



Sec. 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

[[Page 188]]

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.



Sec. 219.105  Definitions.

    Terms used in this subpart shall have the same meaning as in 30 
U.S.C. 1702.



PART 220--ACCOUNTING PROCEDURES FOR DETERMINING NET PROFIT SHARE PAYMENT FOR OUTER CONTINENTAL SHELF OIL AND GAS LEASES--Table of Contents




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 at 48 FR 35642, Aug. 5, 
1983.



Sec. 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 Sec. 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]



Sec. 220.002  Definitions.

    For purposes of this part 220:
    Allowance for capital recovery means the amount calculated according 
to procedures specified in Sec. 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

[[Page 189]]

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 Sec. 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 Sec. 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 Sec. 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 Sec. 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 
Sec. 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.

[[Page 190]]

    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 
Sec. 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]



Sec. 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 Sec. 220.012, and allowances for capital recovery calculated 
pursuant to Sec. 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]



Sec. 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 Sec. 220.012, 
and allowances for capital recovery calculated pursuant to Sec. 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.

[[Page 191]]



Sec. 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 Sec. 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 
Sec. 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

[[Page 192]]

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 furnish by a lessee as NPSL 
property shall be charged or credited at amounts specified in 
Sec. 220.015. The purchase and inventorying of materiel is subject to 
the conditions and provisions in Sec. 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 Sec. 220.020, the credit shall be 
calculated pursuant to Sec. 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 Sec. 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:

[[Page 193]]

    (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 Sec. 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   Hour or unit.
   work).
  Shore base production facilities........  Volume.

[[Page 194]]

 
  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 
Sec. 220.020, the credit shall be calculated pursuant to 
Sec. 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 Sec. 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.

[[Page 195]]

    (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 Sec. 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.



Sec. 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 Sec. 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 Sec. 220.021(c)(2).
    (c) Overhead shall not be charged on the value of:
    (1) Lease rental (Sec. 220.011(a));
    (2) Contract services (Sec. 220.011(e));
    (3) Taxes (Sec. 220.011(i));
    (4) Re-injected hydrocarbons, originally produced from the NPSL 
tract, that are charged under Sec. 220.011(c); and
    (5) Credits for materiel charged under Sec. 220.011(c) that are 
salvaged, returned, or used for the benefit of non-NPSL operations.



Sec. 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 Sec. 220.011(g));
    (c) Depreciation, depletion, amortization, or any other charge for 
capital recovery for materiel charged to the NPSL capital account under 
Sec. 220.011(c), except as explicitly provided by the allowance for 
capital recovery calculated according to Sec. 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 Sec. 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;

[[Page 196]]

    (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 Sec. 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.



Sec. 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.



Sec. 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 
Sec. 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.

[[Page 197]]

    (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 Sec. 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.



Sec. 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 
Sec. 220.012(c); plus
    (2) The value of contract services chargeable to the NPSL capital 
account during the month pursuant to Sec. 220.011(e); plus
    (3) The capital recovery period overhead allowance, calculated in 
accordance with Sec. 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 Sec. 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 Sec. 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.



Sec. 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

[[Page 198]]

month, calculated in accordance with Sec. 260.110(b) of this chapter.
    (3) Credited with amounts properly credited back to the NPSL capital 
account as specified in Sec. 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 Sec. 220.012(a) and debited to the NPSL 
capital account.
    (3) The allowance for capital recovery shall be calculated in 
accordance with Sec. 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 
Sec. 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]



Sec. 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 Sec. 220.021 by the 
net profit share rate. The net profit share payment shall be paid to the 
United States in accordance with Sec. 220.031.



Sec. 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

[[Page 199]]

Sec. 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 Sec. 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.



Sec. 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.



Sec. 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.

[[Page 200]]

    (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 
Sec. 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 Sec. 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 Sec. 220.020, the credit shall be calculated 
pursuant to Sec. 220.021(a)(3).



Sec. 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

[[Page 201]]

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 Sec. 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 Sec. 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.



Sec. 220.034  Redetermination and appeals.

    (a) If, as a result of an inspection of records or an audit under 
Sec. 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.



PART 227--DELEGATION TO STATES--Table of Contents




Sec.

                   Delegation of MMS Royalty Functions

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?

[[Page 202]]

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



Sec. 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.



Sec. 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.



Sec. 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

[[Page 203]]

    (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]



Sec. 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



Sec. 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 Royalty 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

[[Page 204]]

    (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

[[Page 205]]

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.



Sec. 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 Sec. 227.103 requires. Once you submit all 
required information, MMS will notify you of the date your application 
is complete.

                             Hearing Process



Sec. 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



Sec. 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.



Sec. 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

[[Page 206]]

within 90 days after your delegation proposal is considered complete 
under Sec. 227.104. MMS may extend the 90-day period with your written 
consent.



Sec. 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.



Sec. 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.



Sec. 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 Sec. 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 Royalty 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 
Royalty Management.

                          Existing Delegations



Sec. 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

[[Page 207]]

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



Sec. 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



Sec. 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;

[[Page 208]]

    (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 
Sec. 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 Sec. 227.201 of this 
part.



Sec. 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 Secs. 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.



Sec. 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.



Sec. 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;

[[Page 209]]

    (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.



Sec. 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.



Sec. 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 216, the PAAS 
Onshore Oil and Gas Reporter Handbook, the PAAS Reporter Handbook-Lease, 
Facility/Measurement Point, and Gas Plant Operators, any interagency 
memorandums 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.



Sec. 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

[[Page 210]]

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.



Sec. 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 
into the Auditing and Financial System (AFS) and the Production 
Accounting and Auditing System (PAAS) 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.



Sec. 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

[[Page 211]]

    (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.



Sec. 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.



Sec. 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



Sec. 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 
Sec. 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;

[[Page 212]]

    (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.



Sec. 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 Sec. 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 Sec. 227.802 to terminate all or a 
part of your delegation agreement;
    (2) Withhold compensation provided to you under Sec. 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.



Sec. 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 
Sec. 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.



Sec. 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:

[[Page 213]]

    (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 
Sec. 227.106 of this part.



Sec. 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.



Sec. 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.



PART 228--COOPERATIVE ACTIVITIES WITH STATES AND INDIAN TRIBES--Table of Contents




                      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



Sec. 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.



Sec. 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.



Sec. 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]



Sec. 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.



Sec. 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.

[[Page 214]]

    (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.



Sec. 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 Auditing and Financial System and the Production Accounting and 
Auditing System, the official accounting systems for royalty reporters 
and payors maintained by the MMS.



Sec. 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



Sec. 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

[[Page 215]]

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 
Sec. 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]



Sec. 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.



Sec. 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.



Sec. 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]



Sec. 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.

[[Page 216]]

    (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.



Sec. 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]



Sec. 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]



Sec. 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.

[[Page 217]]



PART 229--DELEGATION TO STATES--Table of Contents




                      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.



Sec. 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.



Sec. 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.



Sec. 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]



Sec. 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.



Sec. 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.



Sec. 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.).

[[Page 218]]

                      Administration of Delegations



Sec. 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]



Sec. 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]



Sec. 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);

[[Page 219]]

    (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]



Sec. 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 
Sec. 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]



Sec. 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 
Sec. 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]



Sec. 229.105  Evidence of Indian agreement to delegation.

    In the case of a State seeking a delegation of authority for Indian 
lands as

[[Page 220]]

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]



Sec. 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]



Sec. 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]



Sec. 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]



Sec. 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]



Sec. 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--

[[Page 221]]

    (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]



Sec. 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 
Sec. 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.



Sec. 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.



Sec. 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 Sec. 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).



Sec. 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

[[Page 222]]

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.



Sec. 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

[[Page 223]]

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]



Sec. 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.



Sec. 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.



Sec. 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

[[Page 224]]

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.



Sec. 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--Table of Contents




                      Subpart A--General Provisions

Sec.
230.51  Cross-lease netting in calculation of overpayments under section 
          10 of the OCSLA.

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]

Subpart J--Refunds and Recoupments of Overpayments Under Federal Leases on 
the Outer Continental Shelf; Impementation of Section 10 of the Outer 
Continental Shelf Lands Act

230.451  Scope.
230.452  Definitions.
230.453  Request for refund or credit.
230.454  Interest on excess payments.
230.455  Authorization of refund or credit and subsequent audit.
230.456  Offsets of overpayments and underpayments on the same lease (or 
          unit) by the same person.
230.457  Offsets among different persons who reported and paid royalties 
          on a lease for the same prior sales month.
450.458  Unauthorized credit adjustments.
230.549  Stopping or tolling of the section 10(a) 2-year period.
230.460  Lease suspension.
230.461  Transactions not subject to section 10.

    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; 31 U.S.C. 3720A; 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: 57 FR 62207, Dec. 30, 1992, unless otherwise noted.



                      Subpart A--General Provisions



Sec. 230.51  Cross-lease netting in calculation of overpayments under section 10 of the OCSLA.

    (a) The amount of any refund or credit for any overpayment for any 
lease or leases governed by the Outer Continental Shelf Lands Act 
(OCSLA), as amended, for any production month shall not be reduced by 
offsetting against that overpayment any reported underpayment by the 
payor on any other lease or leases, except as provided in paragraph (b) 
of this section.

[[Page 225]]

    (b) Royalties attributed to production from a lease or leases 
governed by the OCSLA, which should have been attributed to production 
from a different lease or leases governed by the OCSLA, may be offset 
without regard to the provisions of OCSLA section 10, 43 U.S.C. 1339, 
only if the payor submits a written request to Minerals Management 
Service (MMS), Fiscal Accounting Division, for its approval of the 
correction and provides adequate documentation to show that the 
following conditions exist and 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 that 
production was not produced for the same or another production month;
    (2) The payor is the same for the lease or leases to which the 
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; and
    (4) In the case of leases which are within the zone defined and 
governed by section 8(g) of the OCSLA, as amended, 43 U.S.C. 1337(g), 
the leases are located off the coast of the same State.
    (c) If MMS approves a correction pursuant to paragraph (b) of this 
section, the payor is required to submit an adjusting royalty report 
(Form MMS-2014) pursuant to 30 CFR part 210 to correct its reporting to 
the Auditing and Financial System.
    (d) If MMS requires a repayment of principal royalties or assesses 
late-payment interest as a result of the payor having improperly offset 
any underpayment against an overpayment and, therefore, having failed to 
request a refund or credit as required by section 10 of the OCSLA, 43 
U.S.C. 1339, and the payor asserts pursuant to 30 CFR part 290 that some 
or all of the royalties or 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.
    (e) The exception set forth in paragraph (b) of this section shall 
not operate to relieve any payor of any liability imposed by statute or 
regulation for erroneous reporting.

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]



Subpart J--Refunds and Recoupments of Overpayments Under Federal Leases 
  on the Outer Continental Shelf; Implementation of Section 10 of the 
                    Outer Continental Shelf Lands Act

    Source: 59 FR 38363, July 28, 1994, unless otherwise noted.



Sec. 230.451  Scope.

    This subpart establishes the procedures that lessees and other 
persons who make royalty and other payments on Federal oil and gas 
leases on the Outer Continental Shelf (OCS) must follow to recover 
certain excess payments made in connection with their leases in 
accordance with section 10 of the Outer Continental Shelf Lands Act 
(section 10), 43 U.S.C. 1339. The requirements of this subpart apply to 
both requests for refund from the Treasury of

[[Page 226]]

excess payments and requests to recover excess payments by recouping the 
amount through a credit adjustment. This subpart applies only to Federal 
leases on the OCS.



Sec. 230.452  Definitions.

    Terms used in this subpart shall have the same meaning as in 30 
U.S.C. 1702.

In addition, the following definitions apply to this subpart:
    Credit or crediting means reduction of a current or future royalty 
or other payment made in connection with a lease as a result of 
reporting a credit adjustment.
    Credit Adjustment means any adjustment reported on a Report of Sales 
and Royalty Remittance (Form MMS-2014) or any other royalty report form 
which reduces any royalty or other payment made in connection with a 
lease which was reported and paid in any previous period.
    Offset means to net or cancel previous overpayments against previous 
underpayments on the same OCS lease or across lease boundaries if all 
the individual leases are part of an approved unit agreement.
    Overpayment means any payment made in excess of the amount that the 
lessee was lawfully required to pay.
    Payment means money MMS receives in satisfaction of a lessee's 
royalty, rental, bonus, net profit share, or late payment interest 
obligation as established by statute, regulation, or the terms of a 
lease.
    Recoup or recoupment means to recover a previous overpayment through 
a credit against a current or future royalty or other payment or 
liability under an OCS lease. A recoupment occurs whenever a payor 
reports a credit adjustment on a Form MMS-2014 or other royalty report 
form resulting in a net negative dollar value for the transaction and 
the credit is taken against the royalty or other payment or liability 
shown in the balance of the report.
    Refund means a repayment by the United States Treasury to a person 
of any overpayment.
    Unit means an area of 2 or more leases subject to an agreement for 
the consolidated development and recovery of oil and gas contained on 
the leases which are part of the agreement approved by MMS.



Sec. 230.453  Request for refund or credit.

    (a) Except as otherwise provided in this subpart, no person may 
recover an excess payment it has made in connection with an OCS lease 
unless:
    (1) That person has made a request for refund or credit in 
accordance with the provisions of this subpart;
    (2) MMS has transmitted a report on the request for refund or credit 
to the President of the Senate and the Speaker of the House of 
Representatives and 30 days have expired since the submission in 
accordance with section 10(b), 43 U.S.C. 1339(b); and
    (3) MMS notifies the person that its request for refund or credit is 
authorized and that the person may receive its refund for, or may report 
a credit adjustment to recoup, the excess payment.
    (b) A request for refund or credit must:
    (1) Be in writing;
    (2) Provide the person's MMS-established payor code;
    (3) Identify the leases and sales months with respect to which the 
excess payments occurred;
    (4) Identify the amount of the excess payment or, with specificity, 
describe a class of payments that are, or as a result of an 
administrative or judicial decision or other identified contingency, may 
become, excess payments;
    (5) Provide the reasons why a refund or credit is due;
    (6) Include a certification that, to the best of the person's 
knowledge or belief, the information provided in response to paragraphs 
(b)(2) through (b)(5) of this section is accurate and complete.
    (c) If MMS determines that a request for refund or credit is 
incomplete, the person who submitted the request will have 30 days, or 
such time as MMS may specify, following notice from MMS, to supplement 
the request for refund or credit.
    (d) A credit adjustment reported on a Form MMS-2014 does not 
constitute a

[[Page 227]]

request for refund or credit for purposes of this section, and does not 
constitute an incomplete request for refund or credit for purposes of 
paragraph (c) of this section.
    (e) A person who has filed a request for refund or credit pursuant 
to this section may amend that request to add an additional amount if:
    (1) The additional amount is for the same lease and sales month; and
    (2) The reason for the excess payment for the additional amount is 
the same as for the originally requested amount.
    (f) Except as otherwise provided in this subpart, no request for a 
refund or credit will be approved unless the request is received at MMS 
at the address provided below within 2 years of the date that MMS 
received the excess payment.
    (1) The request for refund or credit must be received at the 
following address:
    (i) By mail: Minerals Management Service, Section 10 Refund 
Requests, P.O. Box 173702, Denver, CO 80217-3702.
    (ii) By express delivery or courier: Minerals Management Service, 
Section 10 Refund Requests, Building 85, Denver Federal Center, Room A-
212, Denver, CO 80225.
    (2) If the last day of the 2-year period from the date MMS received 
the excess payment falls on a Saturday, Sunday, holiday or any other day 
that MMS is not open for business at the address specified in paragraph 
(f)(1) of this section, then the last day of the 2-year period will be 
the next regular business day. Requests received at the specified MMS 
address after 4 p.m. Mountain Time are considered received the following 
business day.



Sec. 230.454  Interest on excess payments.

    No person is entitled to interest on any excess payment made in 
connection with a lease that is refunded or recouped pursuant to this 
subpart.



Sec. 230.455  Authorization of refund or credit and subsequent audit.

    MMS may grant a refund or authorize a credit based upon satisfactory 
evidence that the payment for which a refund or credit is requested was 
made, and upon a determination that the payment was excess. An approved 
request for refund or credit may be subject to later review or audit by 
MMS. If, based upon later review or audit, MMS determines that the 
refund or credit should not have been granted or authorized, the person 
who requested the refund or credit must repay the amount refunded or 
recouped plus interest determined pursuant to 30 U.S.C. 1721(a) and 30 
CFR 218.150 from the date the refund was made or the recoupment taken 
until the date it is repaid.



Sec. 230.456  Offsets of overpayments and underpayments on the same lease (or unit) by the same person.

    If a person makes an overpayment on any OCS lease or unit in a prior 
month, it may offset that overpayment against an underpayment that same 
person made in any prior month on that same lease or unit for the same 
or a different product without submitting a request for refund or 
credit. This offset is permitted only if the underpayment was not 
created as a result of a credit adjustment to recoup the amount of the 
overpayment or was not otherwise created intentionally to provide an 
underpayment against which to offset the overpayment. This offset also 
is subject to any limitations imposed by other applicable law or 
regulations.



Sec. 230.457  Offsets among different persons who reported and paid royalties on a lease for the same prior sales month.

    (a) This section applies to any reallocation of production for a 
prior sales month among different persons who reported and paid royalty 
for that month on a lease or unit, except for reallocations of 
production that result from the approval or amendment of a unit 
agreement subject to Sec. 230.461(b).
    (b) In the event of a reallocation of production as described in 
paragraph (a) of this section, the respective persons who reported and 
paid royalty may reconcile any resulting differences in royalty payment 
obligations between themselves without submitting revised royalty 
reports or requests for refund or credit to MMS under this subpart, 
except that:
    (1) Any person who paid any amount which remains as a net 
overpayment after such reconciliation must file a request for refund or 
credit in accordance

[[Page 228]]

with the requirements of this subpart to recover the excess payment;
    (2) Any person whose royalty obligation remains underpaid after such 
reconciliation must report the additional royalties due for the prior 
sales month on a Form MMS-2014 and pay interest on the underpayment from 
the last day of the month following the sales month until the date the 
additional royalties are paid; and
    (3) All persons involved in such reconciliation must retain all 
documents pertaining to the reallocation of production, calculation of 
royalties due, and the subsequent reconciliation among the persons 
involved together with other records pertaining to production from that 
lease during the prior sales month and the royalty due and paid thereon, 
and make such documents available for review and audit in the same 
manner as other records pertaining to the lease.
    (c) If persons who reported and paid royalty do not reconcile 
between themselves any differences in royalty payment obligations 
arising as a result of a reallocation as provided in paragraph (b) of 
this section, each person who pays royalties for the lease must report 
and pay any additional royalties due, or file a request for refund or 
credit in accordance with the requirements of this subpart to recover 
the excess payment, as applicable. Any person who reports additional 
royalties due for the prior sales month must pay interest pursuant to 30 
CFR 218.54 on the underpayment from the last day of the month following 
the sales month until the date the additional royalties are paid.



Sec. 230.458  Unauthorized credit adjustments.

    (a) If a person reports a credit adjustment on Form MMS-2014 that 
results in a credit before MMS approves the recoupment pursuant to 
Sec. 230.455, and if the credit adjustment does not qualify as one of 
the transactions not subject to section 10 as provided in Sec. 230.461, 
then that person has taken an unauthorized credit adjustment.
    (1) If the unauthorized credit adjustment recouped a payment that 
MMS received more than 2 years before the date MMS received the Form 
MMS-2014 which includes the unauthorized credit adjustment, the person 
must repay the amount recouped plus late payment interest determined 
pursuant to 30 U.S.C. 1721(a) and 30 CFR 218.150 from the date the 
unauthorized recoupment was taken until the date it is repaid. Unless 
the person filed a request for refund or credit pursuant to Sec. 230.453 
within 2 years of the making of the excess payment for which the 
unauthorized credit adjustment was reported, the excess payment is not 
subject to refund or recoupment.
    (2) If the unauthorized credit adjustment recouped a payment that 
MMS received less than 2 years before the date MMS received the Form 
MMS-2014 with the unauthorized credit adjustment, the person must repay 
the amount recouped plus late payment interest determined pursuant to 30 
U.S.C. 1721(a) and 30 CFR 218.150 from the date the unauthorized 
recoupment was taken until the date it is repaid. The report of the 
unauthorized credit adjustment on the Form MMS-2014 does not constitute 
a request for refund or credit that tolls the 2-year period in section 
10(a), 43 U.S.C. 1339(a). The person may file a request for refund or 
credit pursuant to section 230.453 for the payment for which the 
unauthorized credit adjustment was reported. MMS will review the request 
pursuant to the requirements of this subpart only if the request for 
refund or credit is received within 2 years of the making of the 
original payment for which the unauthorized credit adjustment was 
reported.
    (b) A person who reports an unauthorized credit adjustment to MMS on 
a Form MMS-2014 will be assessed $500 for each unauthorized credit 
adjustment reported.



Sec. 230.459  Stopping or tolling of the section 10(a) 2-year period.

    (a) The period of 2 years from the making of the excess payment, 
within which a request for refund or credit must be filed under section 
10(a), 43 U.S.C. 1339(a), will be:
    (1) Tolled by MMS's receipt of a substantially complete request for 
refund or credit pursuant to Sec. 230.453; or
    (2) Tolled by a general tolling notice issued by MMS and published 
in the

[[Page 229]]

Federal Register in circumstances where MMS believes a substantial 
number of requests for refund or credit could result as a consequence of 
a pending administrative or judicial proceeding or other action. The 
running of the 2-year period will be tolled for the time period 
specified in the notice; or
    (3) Stopped by an application for unitization of OCS leases with 
respect to any excess payment that may result from the reallocation of 
production among leases after the unit or revision is approved; or
    (4) Tolled by a notice filed by a person at the address stated in 
Sec. 230.453(f) stating that a specifically identified action or 
proceeding may result in payments made on an OCS lease becoming excess 
payments. The notice must include:
    (i) A list of affected leases and sales months;
    (ii) The specific action or proceeding that could result in payments 
becoming excess;
    (iii) An estimate of the amount that could be subject to a request 
for refund or credit; and
    (iv) The person's MMS-established payor code.
    (b) A request for refund or credit that is filed timely by a person 
who made an excess payment on an OCS lease does not stop or toll the 
running of the 2-year period with respect to any excess payment made by 
any other person on that lease.



Sec. 230.460  Lease suspension.

    If MMS suspends an OCS lease pursuant to 30 CFR 250.10(b)(6), a 
person who has made excess rental payments for the period of suspension 
may request a refund or credit of any excess payments pursuant to this 
subpart. If the request for refund or credit is filed more than 2 years 
after MMS received the excess rentals, the excess payment will not be 
refunded, recouped, or credited against future rentals due on the same 
lease.



Sec. 230.461  Transactions not subject to section 10.

    (a) A request for refund of, or any other action to recover, excess 
payments made by a refiner/purchaser under a royalty-in-kind contract 
for royalty oil produced from an OCS lease is not subject to section 10.
    (b) If MMS approves a unit agreement on the OCS, or a revision to a 
unit, a person may file amended Forms MMS-2014 within the time period 
MMS prescribes, reallocating production among its affected leases. A 
person must file a request for refund or credit pursuant to this subpart 
only if, and to the extent that, there is a net reduction in the royalty 
that person previously paid for the leases committed to the unit as a 
result of the amendments.
    (c) A person may amend Form MMS-2014 to adjust volume and royalty 
reports among OCS leases within a unit within the same sales month 
without filing a request for refund or credit pursuant to this subpart, 
except that a request for refund or credit must be filed to the extent 
that there is a net reduction in the royalty previously paid for the 
leases committed to the unit as a result of the amendments.
    (d) A person who pays more money than the total royalty due as 
reported on the Form MMS-2014 accompanying the payment, where all 
amounts reported on the Form MMS-2014 are correct, may submit a request 
for refund of the overpaid amounts. The request for refund is not 
subject to section 10's requirements unless the Form MMS-2014 includes 
reports for only one OCS lease. Any overpayment subject to this 
paragraph may not be recovered by recoupment.
    (e) A person may reduce an estimate balance, established for any 
lease product pursuant to MMS instructions, by submitting a credit 
adjustment on a Form MMS-2014, or a request for refund, for all or part 
of the established estimate balance. A credit adjustment or request for 
refund to recover all or part of an estimate balance authorized by this 
paragraph is not subject to the requirements of section 10.
    (f)(1) If adjustment of an estimated oil transportation allowance or 
estimated gas transportation allowance pursuant to 30 CFR 206.105(e) and 
206.157(e), respectively, results in an overpayment for any sales month 
because the estimated transportation costs were less than the actual 
costs, a person may submit a credit adjustment

[[Page 230]]

on a Form MMS-2014 to recoup, or may request a refund of, the 
overpayment. The credit adjustment or request for refund authorized by 
this paragraph is not subject to the requirements of section 10, and MMS 
approval is not required before reporting the credit adjustment.
    (2) If adjustment of an estimated gas processing allowance pursuant 
to 30 CFR 206.159(e) results in an overpayment for any sales month 
because the estimated processing costs were less than the actual costs, 
a person may submit a credit adjustment on a Form MMS-2014 to recoup, or 
may request a refund of, the overpayment. The credit adjustment or 
request for refund authorized by this paragraph is not subject to the 
requirements of section 10, and MMS approval is not required before 
reporting the credit adjustment.
    (3) If a person makes an error in the report of actual 
transportation or processing costs pursuant to paragraphs (f)(1) or 
(f)(2) of this section, any subsequent adjustment to the report that 
results in a credit is subject to section 10 and the requirements of 
this subpart.
    (g) If a person pays pursuant to an MMS order and challenges the 
obligation to pay in an administrative appeal or judicial action, and if 
the person is successful in a challenge to all or part of the MMS order 
to pay, section 10 does not apply to the refund or recoupment of the 
disputed payment or portion thereof.
    (h) MMS approval is not required for an adjustment by any person to 
the amount reported for a report month that results in a credit of not 
more than an amount established periodically by MMS and published in the 
Federal Register. However, no adjustment may be reported more than 2 
years after the date MMS received the Form MMS-2014 including the excess 
payment.



PART 232--INTEREST PAYMENTS [RESERVED]






PART 233--ESCROW AND INVESTMENTS [RESERVED]






PART 234--BONDING--PAYMENT LIABILITY [RESERVED]






PART 241--PENALTIES--Table of Contents




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?

[[Page 231]]

                           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.; 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.; 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 [Reserved]



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

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

                               Definitions



Sec. 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



Sec. 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 send the Notice to your address of record as shown in 
the following table:

----------------------------------------------------------------------------------------------------------------
       For notices of
     noncompliance to--                   The addressee of record is--                          And--
----------------------------------------------------------------------------------------------------------------
(1) A refiner or other       The position title, department name and address, or     The refiner or other party
 party involved in            individual name and address in the executed royalty     must notify MMS in writing
 disposition of Federal       sale contract; or a different position title,           of all addressee changes.
 royalty taken in kind.       department name and address, or individual name and
                              address that the refiner or other party under the
                              executed royalty sale contract identifies in writing
                              for billing purposes; or an agent designated in
                              writing to receive notices of noncompliance.
(2) Any person required to   The most recent position title, department name and     The reporter/payor must
 report oil or gas removed    address, or individual name and address that RMP has    notify RMP, in writing, of
 from Federal or Indian       in its records for the reporter/payor; or an agent      any addressee changes.
 leases to the RMP            designated in writing to receive notices of
 Production Accounting and    noncompliance.
 Auditing System.
(3) A lessee, designee,      The position title, department name and address, or     The lessee, designee,
 reporter or payor whose      individual name and address the lessee, designee,       reporter or payor must
 records are subject to       reporter or payor identifies in writing at the          notify MMS of any
 audit.                       initiation of the audit; or the most recent addressee   addressee changes.
                              that the lessee, designee, reporter or payor
                              specified in writing; or an agent designated in
                              writing to receive notices of noncompliance.

[[Page 232]]

 
(4) A reporter reporting on  The most recent position title, department name and     The lessee, designee,
 the ``Report of Sales and    address, or individual name and address that the        reporter or payor is
 Royalty Remittance'' (Form   lessee, designee, reporter or payor identifies in       responsible for notifying
 MMS-2014).                   writing; or an agent designated in writing to receive   RMP in writing of any
                              notices of noncompliance.                               addressee changes.
(5) A lessee, designee,      The most recent position title, department name and     The lessee, designee,
 reporter or payor who        address, or individual name and address maintained in   reporter or payor is
 remits rental and bonuses    RMP records; or an agent designated in writing to       responsible for notifying
 from nonproducing Federal    receive notices of noncompliance.                       RMP in writing of any
 leases.                                                                              addressee changes.
----------------------------------------------------------------------------------------------------------------

    (c) We will serve Notices of Noncompliance by using registered mail 
or personal service.



Sec. 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).



Sec. 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.



Sec. 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, 4015 Wilson 
Boulevard, Arlington, Virginia 22203. You may do this regardless of 
whether you correct the violations identified in the Notice of 
Noncompliance.



Sec. 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 Sec. 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).

[[Page 233]]



Sec. 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 
Sec. 241.54. If you did not request a hearing on the record on the 
Notice of Noncompliance under Sec. 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, 4015 
Wilson Boulevard, Arlington, Virginia 22203.

                  Penalties Without a Period To Correct



Sec. 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.



Sec. 241.61  How will MMS inform me of violations without a period to correct?

    We will inform you of violations without a period to correct by 
issuing a Notice of Noncompliance explaining what the violation is and 
how to correct it. We also will send you a Notice of Civil Penalty 
stating the amount of the penalty. The Notice of Noncompliance and 
Notice of Civil Penalty may be issued simultaneously. We will send the 
Notice of Noncompliance and the Notice of Civil Penalty to your address 
of record under Sec. 241.51(b) using the means of service specified 
under Sec. 241.51(c).



Sec. 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, 4015 Wilson Boulevard, Arlington, Virginia 
22203. You may do this regardless of whether you correct the violations 
identified in the Notice of Noncompliance.



Sec. 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

[[Page 234]]

on the record and a decision by the Administrative Law Judge under 
Sec. 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).



Sec. 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 Sec. 241.62. If you did 
not request a hearing on the record on the Notice of Noncompliance under 
Sec. 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, 4015 
Wilson Boulevard, Arlington, Virginia 22203.

                           General Provisions



Sec. 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.



Sec. 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 
Sec. 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.



Sec. 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 Secs. 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.



Sec. 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.



Sec. 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.



Sec. 241.75  When must I pay the penalty?

    (a) You must pay the amount of the Notice of Civil Penalty issued 
under Secs. 241.53 or 241.61, if you do not request a hearing on the 
record under Sec. 241.54, Sec. 241.56, Sec. 241.62, or Sec. 241.64.
    (b) If you request a hearing on the record under Sec. 241.54, 
Sec. 241.56, Sec. 241.62, or Sec. 241.64, but you do not appeal the 
determination of the Administrative Law Judge to the Interior Board of 
Land Appeals under Sec. 241.73, you must pay the amount assessed by the 
Administrative Law Judge.

[[Page 235]]

    (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 Sec. 241.54, Sec. 241.56, 
Sec. 241.62, or Sec. 241.64;
    (2) You received an Administrative Law Judge's decision under 
Sec. 241.72, if you obtained a stay of the accrual of penalties pending 
the hearing on the record under Sec. 241.55(b) or Sec. 241.63(b) and did 
not appeal the Administrative Law Judge's determination to the IBLA 
under Sec. 241.73;
    (3) You received an IBLA decision under Sec. 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 Sec. 241.77.



Sec. 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.



Sec. 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 Sec. 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 Sec. 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



Sec. 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 Sec. 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]






PART 243--SUSPENSIONS PENDING APPEAL AND BONDING--ROYALTY MANAGEMENT PROGRAM--Table of Contents




                      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?

[[Page 236]]

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



Sec. 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.



Sec. 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.



Sec. 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 Sec. 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 Royalty 
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

[[Page 237]]

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.



Sec. 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 Sec. 243.5.



Sec. 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 Sec. 243.4(a)(1).



Sec. 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 Sec. 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.



Sec. 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 Sec. 243.5, 
you:
    (a) Must notify MMS in writing at the address specified in 
Sec. 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.



Sec. 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

[[Page 238]]

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.



Sec. 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.



Sec. 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 Sec. 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 
Sec. 243.101(b);
    (5) If the obligation to comply with an order or decision is not 
suspended under Sec. 243.8 or Sec. 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 Sec. 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.

[[Page 239]]



Sec. 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.



Sec. 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



Sec. 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.



Sec. 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



Sec. 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

[[Page 240]]

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.



Sec. 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 Sec. 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.



Sec. 243.202  When will MMS monitor my financial solvency?

    (a) If you are presumptively financially solvent under 
Sec. 243.201(b), MMS will determine your net worth as described under 
Secs. 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 Sec. 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.

[[Page 241]]





                         SUBCHAPTER B--OFFSHORE





PART 250--OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER CONTINENTAL SHELF--Table of Contents






                           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?

                        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?

[[Page 242]]

                               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

250.190  What reporting information and report forms must I submit?
250.191  What accident reports must I submit?
250.192  What evacuation statistics must I submit?
250.193  Reports and investigations of apparent violations.
250.194  What archaeological reports and surveys must I submit?
250.195  Reimbursements for reproduction and processing costs.
250.196  Data and information to be made available to the public.

                               References

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

       Subpart B--Exploration and Development and Production Plans

250.200  General requirements.
250.201  Preliminary activities.
250.202  Well location and spacing.
250.203  Exploration Plan.
250.204  Development and Production Plan.

               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

250.400  Control of wells.
250.401  General requirements.
250.402-250.403  [Reserved]
250.404  Well casing and cementing.
250.405  Pressure testing of casing.
250.406  Blowout preventer systems and system components.
250.407  Blowout preventer (BOP) systems tests, inspections, and 
          maintenance.
250.408  Well-control drills.
250.409  Diverter systems.
250.410  Mud program.
250.411  Securing of wells.
250.412  Field drilling rules.
250.413  Supervision, surveillance, and training.
250.414  Applications for permit to drill.
250.415  Sundry notices and reports on wells.
250.416  Well records.
250.417  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]
250.508  Electrical requirements.
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.

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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--Abandonment of Wells

250.700  General requirements.
250.701  Approvals.
250.702  Permanent abandonment.
250.703  Temporary abandonment.
250.704  Site clearance verification.

            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

250.900  General requirements.
250.901  Application for approval.
250.902  Platform Verification Program requirements.
250.903  Certified Verification Agent duties and nomination.
250.904  Environmental conditions.
250.905  Loads.
250.906  General design requirements.
250.907  Steel platforms.
250.908  Concrete-gravity platforms.
250.909  Foundation.
250.910  Marine operations.
250.911  Inspection during construction.
250.912  Periodic inspection and maintenance.
250.913  Platform removal and location clearance.
250.914  Records.

             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  General requirements for a pipeline right-of-way grant.
250.1010  Applications for a pipeline right-of-way grant.
250.1011  Granting a pipeline right-of-way.
250.1012  Requirements for construction under a right-of-way grant.
250.1013  Assignment of a right-of-way grant.
250.1014  Relinquishment of a right-of-way grant.

                 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?

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        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--Training

250.1500  Question index table.
250.1501  Definitions.
250.1502  What is MMS's goal for well control and production safety 
          systems training?
210.1503  What type of training must I provide for my employees?
250.1504  What documentation must I provide to trainees?
250.1505  How often must I provide training to my employees and for how 
          many hours?
250.1506  Where must I get training for my employees?
250.1507  Where can I find training guidelines for other topics?
250.1508  Can I get an exception to the training requirements?
250.1509  Can my employees change job certification?
250.1510  What must I do if I have temporary employees or on-the-job 
          trainees?
250.1511  What must manufacturer's representatives in production safety 
          systems do?
250.1512  May I use alternative training methods?
250.1513  What is MMS looking for when it reviews an alternative 
          training program?
250.1514  Who may accredit training organizations to teach?
250.1515  How long is a training organization's accreditation valid?
250.1516  What information must a training organization submit to MMS?
250.1517  What additional requirements must a training organization 
          follow?
250.1518  What are MMS's requirements for the written test?
250.1519  What are MMS's requirements for the hands-on simulator and 
          well test?
250.1520  What elements must a basic course cover?
250.1521  If MMS tests employees at my worksite, what must I do?
250.1522  If MMS tests trainees at a training organization's facility, 
          what must occur?
250.1523  Why might MMS conduct its own tests?
250.1524  Can a training organization lose its accreditation?

                      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  Sundry notices and reports on wells.
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.

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

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



                           Subpart A--General

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

[[Page 245]]

                    Authority and Definition of Terms



Sec. 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.



Sec. 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
------------------------------------------------------------------------
 (1) Abandoning wells........................  Sec.  250.701.
 (2) Applications for Permit to Drill........  Sec.  250.414.
 (3) Development and Production Plans (DPP)..  Sec.  250.204.
 (4) Downhole commingling....................  Sec.  250.1106.
 (5) Exploration Plans (EP)..................  Sec.  250.203.
 (6) Flaring.................................  Sec.  250.1105.
 (7) Gas measurement.........................  Sec.  250.1203.
 (8) Off-lease geological and geophysical      30 CFR 251.
 permits.
 (9) Oil spill financial responsibility        30 CFR 253.
 coverage.
(10) Oil and gas production safety systems...  Sec.  250.802.
(11) Oil spill response plans................  30 CFR 254.
(12) Oil and gas well-completion operations..  Sec.  250.513.
(13) Oil and gas well-workover operations....  Sec.  250.613.
(14) Platforms and structures................  Sec.  250.901.
(15) Pipelines...............................  Sec.  250.1009.
(16) Pipeline right-of-way...................  Sec.  250.1010.
(17) Sulphur operations......................  Sec.  250.1604.
(18) Training................................  Sec.  250.1500.
(19) Unitization.............................  Sec.  250.1300.
------------------------------------------------------------------------



Sec. 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.



Sec. 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.



Sec. 250.105  Definitions.

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

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    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.
    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

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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.
    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 Supervisor 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 Sec. 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 Sec. 250.130, any installation permanently or 
temporarily attached to the seabed on the OCS (including manmade islands 
and bottom-sitting structures). It includes mobile

[[Page 248]]

offshore drilling units (MODUs) or other vessels engaged in drilling or 
downhole operations, used for oil, gas, or sulphur drilling, production, 
or related activities. It also includes 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 Sec. 250.303, means any installation or device 
permanently or temporarily attached to the seabed. It includes 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. 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 Sec. 250.417(b), means a vessel, a structure, or an 
artificial island used for drilling, well-completion, well-workover, 
and/or production operations.
    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.
    Governor means the Governor of a State, or the person or entity 
designated by, or under, State law to exercise the powers granted to 
such Governor under the Act.
    H2S absent means:
    (1) Drilling, logging, coring, testing, or producing operations have 
confirmed the absence of H2S in concentrations that could 
potentially result in atmospheric concentrations of 20 ppm or more of 
H2S; or
    (2) Drilling in the surrounding areas and correlation of geological 
and seismic data with equivalent stratigraphic units have confirmed an 
absence of H2S throughout the area to be drilled.
    H2S present means drilling, logging, coring, testing, or 
producing operations have confirmed the presence of H2S in 
concentrations and volumes that could potentially result in atmospheric 
concentrations of 20 ppm or more of H2S.
    H2S unknown means the designation of a zone or geologic 
formation where neither the presence nor absence of H2S has 
been confirmed.
    Human environment means the physical, social, and economic 
components, conditions, and factors that interactively determine the 
state, condition, and quality of living conditions, employment, and 
health of those affected, directly or indirectly, by activities 
occurring on the OCS.
    Interpreted geological information means geological knowledge, often 
in the form of schematic cross sections, 3-dimensional representations, 
and maps, developed by determining the geological significance of data 
and analyzed geological information.
    Interpreted geophysical information means geophysical knowledge, 
often in the form of schematic cross sections, 3-dimensional 
representations, and maps, developed by determining the geological 
significance of geophysical data and analyzed geophysical information.
    Lease means an agreement that is issued under section 8 or 
maintained under section 6 of the Act and that authorizes exploration 
for, and development and production of, minerals. The term also means 
the area covered by that authorization, whichever the context requires.
    Lease term pipelines 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

[[Page 249]]

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, in addition to a natural person, an association 
(including partnerships 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

[[Page 250]]

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.
    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.

[[Page 251]]

    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 agent of the lessee(s), a pipeline right-of-way holder, or a 
State lessee granted a right-of-use and easement.

                          Performance Standards



Sec. 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.



Sec. 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 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.



Sec. 250.108  What requirements must I follow for cranes and other material-handling equipment?

    (a) If you operate a crane installed on fixed platforms you must:
    (1) Follow the American Petroleum Institute (API) Recommended 
Practice (RP) for Operation and Maintenance of Offshore Cranes (API RP 
2D);
    (2) Keep inspection, testing, and maintenance records at the OCS 
facility for at least 2 years; and
    (3) Keep crane operator qualifications at the facility for at least 
4 years.
    (b) You must operate and maintain all other material-handling 
equipment in a manner that ensures safe operations and prevents 
pollution.



Sec. 250.109  What documents must I prepare and maintain related to welding?

    (a) You must submit a Welding Plan to the District Supervisor before 
you begin drilling or production activities on a lease. You may not 
begin welding until the District Supervisor 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.



Sec. 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 Sec. 250.109:

[[Page 252]]

    (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.



Sec. 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.



Sec. 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.



Sec. 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

[[Page 253]]

or a positive overbalance toward the formation.



Sec. 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 Offshore Production Platforms. You do not have to comply with 
Sections 7.4, Emergency Lighting, and 9.4, Aids to Navigation Equipment.
    (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]



Sec. 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 Sec. 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 Supervisor to witness each test that you 
conduct under this section; or
    (2) Receive the District Supervisor'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.



Sec. 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 
Sec. 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

[[Page 254]]

clean water-bearing sand--if mud conditions prevent a 20-negative 
millivolt reading beyond the shale baseline.



Sec. 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.



Sec. 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.



Sec. 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.



Sec. 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 
Sec. 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 
Sec. 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.



Sec. 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.



Sec. 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.



Sec. 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 
Secs. 250.160 through 250.166 of this subpart.



Sec. 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.

                        Inspection of Operations



Sec. 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

[[Page 255]]

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.



Sec. 250.131  Will MMS notify me before conducting an inspection?

    MMS conducts both scheduled and unscheduled inspections.



Sec. 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.



Sec. 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



Sec. 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.



Sec. 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



Sec. 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    We will send you a written approval
                                           if quick action is needed.   afterward. It will include any
                                                                        conditions that we place on the oral
                                                                        approval.
(c) Request approval orally for gas       Give you an oral approval..  You don't have to follow up with a
 flaring.                                                               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.)
----------------------------------------------------------------------------------------------------------------


[[Page 256]]



Sec. 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 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.



Sec. 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 or Regional Supervisor.

[65 FR 6536, Feb. 10, 2000]



Sec. 250.143  How do I designate an operator?

    (a) You must provide the Regional Supervisor an executed Designation 
of Operator form 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.



Sec. 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.



Sec. 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.



Sec. 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.

[[Page 257]]

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



Sec. 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.



Sec. 250.151  How do I name facilities in the Pacific Region?

    The operator assigns a name to the facility.



Sec. 250.152  How do I name facilities in the Alaska Region?

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



Sec. 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.



Sec. 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.

[[Page 258]]

    (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



Sec. 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.



Sec. 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.



Sec. 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.



Sec. 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.

[[Page 259]]



Sec. 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.



Sec. 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 Sec. 0.1010(a); and
    (b) The first year's rental as specified in Sec. 250.1009(c)(2).



Sec. 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 Sec. 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



Sec. 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).



Sec. 250.169  What effect does suspension have on my lease?

    (a) A suspension may extend the term of a lease (see 
Sec. 250.180(b)). 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.



Sec. 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.



Sec. 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).

[[Page 260]]

    (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 Secs. 250.115, 250.116, or 
250.1603 (SOP only); and
    (d) A commitment to production (SOP only).



Sec. 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 Sec. 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.



Sec. 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.



Sec. 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).



Sec. 250.175  When may the Regional Supervisor grant an SOO?

    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.



Sec. 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 Sec. 218.154.



Sec. 250.177  What additional requirements may the Regional Supervisor order for a suspension?

    If MMS grants or directs a suspension under paragraph 
Sec. 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.

[[Page 261]]

    (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



Sec. 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 Supervisor 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 Secs. 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 Sec. 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 Supervisor 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 Supervisor 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:

[[Page 262]]

    (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 Supervisor if operations do not begin 
before the end of the 180-day period.



Sec. 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 Sec. 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.



Sec. 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.



Sec. 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.



Sec. 250.184  What is the amount of compensation for lease cancellation?

    When the Secretary cancels a lease under Secs. 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:

[[Page 263]]

    (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.



Sec. 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



Sec. 250.190  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 Regional or District Supervisor.
    (2) Instead of paper copies of forms available from the Regional or 
District 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 Sec. 250.196 or otherwise exempt 
from public disclosure under law or regulation.



Sec. 250.191  What accident reports must I submit?

    (a) You must notify the District Supervisor of all serious 
accidents, any death or serious injury, and all fires, explosions, and 
blowouts connected with any activities or operations on the lease. You 
must report all spills of oil or other liquid pollutants according to 30 
CFR part 254.
    (b) If you hold an easement, right-of-way, or other permit, and your 
operation is related to the exercise of the easement, right-of-way, or 
other permit, you must comply with paragraph (a) by notifying and 
reporting to the Regional Supervisor any accidents occurring on the area 
covered by the easement, right-of-way, or other permit.

[[Page 264]]

    (c) Any investigation that the Secretary or the U.S. Coast Guard 
(USCG) 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 
civil or criminal issues and no adverse parties. The purpose of the 
investigation is to prepare a public report that determines the cause or 
causes of the accident. The investigation may involve panel meetings 
conducted by a chairperson appointed by MMS. The following requirements 
must be met for any panel meetings involving persons giving testimony:
    (1) A person giving testimony may have legal and/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.
    (2) Only panel members, panel's legal advisors, and any experts the 
panel deems necessary may address questions to any person giving 
testimony.
    (3) The chairperson may issue subpoenas to persons to appear and 
provide testimony and/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.
    (4) Any person giving testimony may request compensation for mileage 
and fees for service within 90 days after the panel meeting. The 
compensated expenses must be similar to mileage and fees the U.S. 
District Courts allow.



Sec. 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.



Sec. 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.



Sec. 250.194  What archaeological reports and surveys must I submit?

    (a) If it is likely that an archaeological resource exists in the 
lease area, the Regional Director will notify you in writing. You must 
include an archaeological report in the EP or DPP. 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

[[Page 265]]

the Regional Director has told you how to protect the resource.
    (c) If you discover any archaeological resource while conducting 
operations in the lease 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.



Sec. 250.195  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.



Sec. 250.196  Data and information to be made available to the public.

    MMS will protect data and information you submit under this part, as 
described in this section. The tables in 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 and under what circumstances 
and in what time period.
    (a) MMS will disclose data and information you submit on MMS forms 
according to the following table:

----------------------------------------------------------------------------------------------------------------
   Data and information that you
           submit on form            In the following items     Will be released                 And
----------------------------------------------------------------------------------------------------------------
(1) MMS-123, Application for Permit  All entries except      At any time...........  The data and information in
 to Drill.                            items 17, 24, and 25.                           items 17, 24, and 25 will
                                                                                      be released according to
                                                                                      the table in paragraph (b)
                                                                                      of this section or when
                                                                                      the well goes on
                                                                                      production, whichever is
                                                                                      earlier.
(2) MMS-124, Sundry Notices and      All entries except      At any time...........  The data and information in
 Reports on Wells.                    item 36.                                        item 36 will be released
                                                                                      according to the table in
                                                                                      paragraph (b) or when the
                                                                                      well goes on production,
                                                                                      whichever is earlier.
(3) MMS-125, Well Summary Report...  All entries except      At any time...........  The data and information in
                                      items 17, 24, 34, 37,                           the excepted items will be
                                      and 46 through 87.                              released according to the
                                                                                      table in paragraph (b) of
                                                                                      this section or when the
                                                                                      well goes on production,
                                                                                      whichever is earlier.
                                                                                      However, items 78 through
                                                                                      87 will not be released
                                                                                      when the well goes on
                                                                                      production unless the
                                                                                      period of time in the
                                                                                      table in paragraph (b) has
                                                                                      expired
(4) MMS-126, Well Potential Test     All entries except      When the well goes on   The data and information in
 Report.                              item 101.               production.             item 101 will be released
                                                                                      2 years after you submit
                                                                                      it.
(5) MMS-127, Request for Reservoir   All entries except      At any time...........  The data and information in
 Maximum Efficient Rate (MER).        items 124 through 168.                          items 124 through 168 will
                                                                                      be released according to
                                                                                      the time periods in the
                                                                                      table in paragraph (b) of
                                                                                      this section.
(6) MMS-128, Semiannual Well Test    All entries...........  At any time...........
 Report.
----------------------------------------------------------------------------------------------------------------


[[Page 266]]

    (b) MMS will disclose lease data and information that you submit, 
but that are not usually submitted on MMS forms, according to the 
following table:

----------------------------------------------------------------------------------------------------------------
                 If                     MMS will release          At this time            Special provisions
----------------------------------------------------------------------------------------------------------------
(1) The Director determines that     Geophysical data,       At any time...........  Data and information will
 data and information are needed to   Geological data,                                be shown only to persons
 unitize operations on two or more    Interpreted (G&G)                               with an interest in the
 leases, to determine whether a       information,                                    issue.
 reservoir is competitive to ensure   Processed G&G
 proper plans of development for      information, Analyzed
 competitive reservoirs, or to        geological
 promote operational safety or        information.
 protect the environment.
(2) The Director determines that     Geophysical data,       At any time...........  MMS will release data and
 data and information are needed      Geological data                                 information only if
 for specific scientific or           Interpreted G&G                                 release would further the
 research purposes for the            information,                                    national interest without
 Government.                          Processed G&G                                   unduly damaging the
                                      information, Analyzed                           competitive position of
                                      geological                                      the lessee.
                                      information.
(3) Data or information is           Geophysical data,       60 days after MMS       MMS will release the data
 collected with high-resolution       Geological data,        receives the data or    and information earlier
 systems (e.g., bathymetry, side-     Interpreted G&G         information, if the     than 60 days if the
 scan sonar, subbottom profiler,      information,            Regional Supervisor     Regional Supervisor
 and magnetometer) to comply with     Processed geological    deems it necessary.     determines it is needed by
 safety or environmental protection   information, Analyzed                           affected States to make
 requirements.                        geological                                      decisions under subpart B.
                                      information.                                    The Regional Supervisor
                                                                                      will reconsider earlier
                                                                                      release if you satisfy him/
                                                                                      her that it would unduly
                                                                                      damage your competitive
                                                                                      position.
(4) Your lease is no longer in       Geophysical data,       When your lease         This release time applies
 effect.                              Geological data,        terminates.             only if the provisions in
                                      Processed G&G                                   this table governing high-
                                      information                                     resolution systems and the
                                      Interpreted G&G                                 provisions in Sec.  252.7
                                      information, Analyzed                           do not apply. The release
                                      geological                                      time applies to the
                                      information.                                    geophysical data and
                                                                                      information only if
                                                                                      acquired postlease for a
                                                                                      lessee's exclusive use.
(5) Your lease is still in effect..  Geophysical data        10 years after you      This release time applies
                                      Processed geophysical   submit the data and     only if the provisions in
                                      information,            information.            this table governing high-
                                      Interpreted G&G                                 resolution systems and the
                                      information.                                    provisions in Sec.  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.
(6) Your lease is still in effect    Geological data,        2 years after the       These release times apply
 and within the primary term          Analyzed geological     required submittal      only if the provisions in
 specified in the lease.              information.            date or 60 days after   this table governing high-
                                                              a lease sale if any     resolution systems and the
                                                              portion of an offered   provisions in Sec.  252.7
                                                              lease is within 50      do not apply. If the
                                                              miles of a well,        primary term specified in
                                                              whichever is later.     the lease is extended
                                                                                      under the heading of
                                                                                      ``Suspensions'' in this
                                                                                      subpart, the extension
                                                                                      applies to this provision.
(7) Your lease is in effect and      Geological data,        2 years after the       None.
 beyond the primary term specified    Analyzed geological     required submittal
 in the lease.                        information.            date.
(8) Data is released to the owner    Directional survey      If the lessee from      None.
 of an adjacent lease under subpart   data.                   whose lease the
 D of part 250.                                               directional survey
                                                              was taken consents.
(9) Data and information are         Any data or             At any time...........  None.
 obtained from beneath unleased       information obtained.
 land as a result of a well
 deviation that has not been
 approved by the Regional or
 District Supervisor.
(10) Data and information acquired   Geophysical data,       Geophysical data: 50    None.
 by a permit under part 251 is        Processed geophysical   years, Geophysical
 submitted by a lessee under part     information,            information: 25 years
 250.                                 Interpreted             after you submit it.
                                      geophysical
                                      information.
----------------------------------------------------------------------------------------------------------------


[[Page 267]]

                               References



Sec. 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 Secs. 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 
Office of the Federal Register, 800 North Capitol Street, NW., Suite 
700, Washington, DC. You may obtain the documents from the publishing 
organizations at the addresses given in the following table:

------------------------------------------------------------------------
                For                               Write to
------------------------------------------------------------------------
ACI Standards.....................  American Concrete Institute, P. O.
                                     Box 19150, Detroit, MI 48219.
AISC Standards....................  American Institute of Steel
                                     Construction, Inc., P.O. Box 4588,
                                     Chicago, IL 60680.
ANSI/ASME Codes...................  American National Standards
                                     Institute, Attention Sales
                                     Department, 1430 Broadway, New
                                     York, NY 10018; and/or American
                                     Society of Mechanical Engineers,
                                     United Engineering Center, 345 East
                                     47th Street, New York, NY 10017.
API Recommended Practices, Specs,   American Petroleum Institute, 1220 L
 Standards, Manual of Petroleum      Street, NW., Washington, DC 20005-
 Measurement Standards (MPMS)        4070.
 chapters.
ASTM Standards....................  American Society for Testing and
                                     Materials, 100 Barr Harbor Drive,
                                     West Conshohocken, PA 19428-2959.
AWS Codes.........................  American Welding Society, 550 NW,
                                     LeJeune Road, P.O. Box 351040,
                                     Miami, FL 33135.
NACE Standards....................  National Association of Corrosion
                                     Engineers, P.O. Box 218340,
                                     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.

------------------------------------------------------------------------
                                               Incorporated by reference
              Title of documents                           at
------------------------------------------------------------------------
ACI Standard 318-95, Building Code             Sec.  250.908(b)(4)(i),
 Requirements for Reinforced Concrete, plus     (b)(6)(i), (b)(7),
 Commentary on Building Code Requirements for   (b)(8)(i), (b)(9),
 Reinforced Concrete (ACI 318R-95).             (b)(10), (c)(3),
                                                (d)(1)(v), (d)(5),
                                                (d)(6), (d)(7), (d)(8),
                                                (d)(9), (e)(1)(i),
                                                (e)(2)(i).
ACI Standard 357R-84, Guide for the Design     Sec.  250.900(g); Sec.
 and Construction of Fixed Offshore Concrete    250.908(c)(2), (c)(3).
 Structures, 1984.
AISC Standard Specification for Structural     Sec.  250.907(b)(1)(ii),
 Steel Buildings, Allowable Stress Design and   (c)(4)(ii), (c)(4)(vii).
 Plastic Design, June 1, 1989, with
 Commentary.

[[Page 268]]

 
ANSI/ASME Boiler and Pressure Vessel Code,     Sec.  250.803(b)(1),
 Section I, Rules for Construction of Power     (b)(1)(i); Sec.
 Boilers, including Appendices, 1998 Edition;   250.1629(b)(1),
 July 1, 1999 Addenda, Rules for Construction   (b)(1)(i).
 of Power Boilers, by ASME Boiler and
 Pressure Vessel Committee Subcommittee on
 Power Boilers; and all Section I
 Interpretations Volume 43.
ANSI/ASME Boiler and Pressure Vessel Code,     Sec.  250.803(b)(1),
 Section IV, Rules for Construction of          (b)(1)(i); Sec.
 Heating Boilers, including Nonmandatory        250.1629(b)(1),
 Appendices A, B, C, D, E, F, H, I, K, and L,   (b)(1)(i).
 and the Guide to Manufacturers Data Report
 Forms, 1998 Edition; July 1, 1999 Addenda,
 Rules for Construction of Heating Boilers,
 by ASME Boiler and Pressure Vessel Committee
 Subcommittee on Heating Boilers; and all
 Section IV Interpretations Volumes 43 and 44.
ANSI/ASME Boiler and Pressure Vessel Code,     Sec.  250.803(b)(1),
 Section VIII, Rules for Construction of        (b)(1)(i); Sec.
 Pressure Vessels, Divisions 1 and 2,           250.1629(b)(1),
 including Nonmandatory Appendices, 1998        (b)(1)(i).
 Edition; July 1, 1999 Addenda, Rules for
 Construction of Pressure Vessels, by ASME
 Boiler and Pressure Vessel Committee
 Subcommittee on Pressure Vessels; and all
 Section VIII Interpretations, Divisions 1
 and 2, Volumes 43 and 44.
ANSI/ASME B 16.5-1988 (including Errata) and   Sec.  250.1002(b)(2).
 B 16.5a-1992 Addenda, Pipe Flanges and
 Flanged Fittings.
ANSI/ASME B 31.8-1995, Gas Transmission and    Sec.  250.1002(a).
 Distribution Piping Systems.
ANSI/ASME SPPE-1-1994 and SPPE-1d-1996         Sec.  250.806(a)(2)(i).
 ADDENDA, Quality Assurance and Certification
 of Safety and Pollution Prevention Equipment
 Used in Offshore Oil and Gas Operations.
ANSI Z88.2-1992, American National Standard    Sec.  250.417(g)(4)(iv),
 for Respiratory Protection.                    (j)(13)(ii).
API MPMS, Chapter 1, Vocabulary, Second        Sec.  250.1201.
 Edition, July 1994, API Stock No., H01002..
API MPMS, Chapter 2, Tank Calibration,         Sec.  250.1202(l)(4).
 Section 2A, Measurement and Calibration of
 Upright Cylindrical Tanks by the Manual
 Strapping Method, First Edition, February
 1995, API Stock No. H022A1.
API MPMS, Chapter 2, Section 2B, Calibration   250.1202(l)(4).
 Sec.  250.1202(l)(4) Calibration of Upright
 Cylindrical Tanks Using the Optical
 Reference Line Method, First Edition, March
 1989, reaffirmed May 1996, API Stock No.
 H30023; also available as ANSI/ASTM D 4738-
 88.
API MPMS, Chapter 3, Tank Gauging, Section     Sec.  250.1202(l)(4).
 1A, Standard Practice for the Manual Gauging
 of Petroleum and Petroleum Products, First
 Edition, December 1994, API Stock No. H031A1.
API MPMS, Chapter 3, Section 1B, Standard      Sec.  250.1202(l)(4).
 Practice for Level Measurement of Liquid
 Hydrocarbons in Stationary Tanks by
 Automatic Tank Gauging, First Edition, April
 1992, reaffirmed January 1997, API Stock No.
 H30060.
API MPMS, Chapter 4, Proving Systems, Section  Sec.  250.1202(a)(3),
 1, Introduction, First Edition, July 1988,     (f)(1).
 reaffirmed October 1993, API Stock No.
 H30081.
API MPMS, Chapter 4, Section 2, Conventional   Sec.  250.1202(a)(3),
 Pipe Provers, First Edition, October 1988,     (f)(1).
 reaffirmed October 1993, API Stock No.
 H30082.
API MPMS, Chapter 4, Section 3, Small Volume   Sec.  250.1202(a)(3),
 Provers, First Edition, July 1988,             (f)(1).
 reaffirmed October 1993, API Stock No.
 H30083.
API MPMS, Chapter 4, Section 4, Tank Provers,  Sec.  250.1202(a)(3),
 First Edition, October 1988, reaffirmed        (f)(1).
 October 1993, API Stock No. H30084.
API MPMS, Chapter 4, Section 5, Master-Meter   Sec.  250.1202(a)(3),
 Provers, First Edition, October 1988,          (f)(1).
 reaffirmed October 1993, API Stock No.
 H30085.
API MPMS, Chapter 4, Section 6, Pulse          Sec.  250.1202(a)(3) and
 Interpolation, Second Edition, May 1999, API   (f)(1).
 Stock No. H04062.
API MPMS, Chapter 4, Section 7, Field          Sec.  250.1202(a)(3) and
 Standard Test Measures, Second Edition,        (f)(1).
 December 1998, API Stock No. H04072.
API MPMS, Chapter 5, Metering, Section 1,      Sec.  250.1202(a)(3).
 General Considerations for Measurement by
 Meters, Third Edition, September 1995, API
 Stock No. H05013.
API MPMS, Chapter 5, Section 2, Measurement    Sec.  250.1202(a)(3).
 of Liquid Hydrocarbons by Displacement
 Meters, Second Edition, November 1987,
 reaffirmed January 1997, API Stock No.
 H30102.
API MPMS, Chapter 5, Section 3, Measurement    Sec.  250.1202(a)(3).
 of Liquid Hydrocarbons by Turbine Meters,
 Third Edition, September 1995, API Stock No.
 H05033.
API MPMS, Chapter 5, Section 4, Accessory      Sec.  250.1202(a)(3).
 Equipment for Liquid Meters, Third Edition,
 September 1995, with Errata, March 1996, API
 Stock No. H05043.
API MPMS, Chapter 5, Section 5, Fidelity and   Sec.  250.1202(a)(3).
 Security of Flow Measurement Pulsed-Data
 Transmission Systems, First Edition, June
 1982, reaffirmed January 1997, API Stock No.
 H30105.
API MPMS, Chapter 6, Metering Assemblies,      Sec.  250.1202(a)(3).
 Section 1, Lease Automatic Custody Transfer
 (LACT) Systems, Second Edition, May 1991,
 reaffirmed July 1996, API Stock No. H30121.
API MPMS, Chapter 6, Section 6, Pipeline       Sec.  250.1202(a)(3).
 Metering Systems, Second Edition, May 1991,
 reaffirmed July 1996, API Stock No. H30126.
API MPMS, Chapter 6, Section 7, Metering       Sec.  250.1202(a)(3).
 Viscous Hydrocarbons, Sescond Edition, May
 1991, reaffirmed July 1996, API Stock No.
 H30127.
API MPMS, Chapter 7, Temperature               Sec.  250.1202(a)(3),
 Determination, Section 2, Dynamic              (l)(4).
 Temperature Determination, Second Edition,
 March 1995, API Stock No. H07022.
API MPMS, Chapter 7, Section 3, Static         Sec.  250.1202(a)(3),
 Temperature Determination Using Portable       (l)(4).
 Electronic Thermometers, First Edition, July
 1985, reaffirmed May 1996, API Stock No.
 H30143.

[[Page 269]]

 
API MPMS, Chapter 8, Sampling, Section 1,      Sec.  250.1202(b)(4)(i),
 Standard Practice for Manual Sampling of       (l)(4).
 Petroleum and Petroleum Products, Third
 Edition, October 1995; also available as
 ANSI/ASTM D 4057-88, API Stock No. H30161.
API MPMS, Chapter 8, Section 2, Standard       Sec.  250.1202(a)(3),
 Practice for Automatic Sampling of Liquid      (l)(4).
 Petroleum and Petroleum Products, Second
 Edition, October 1995; also available as
 ANSI/ASTM D 4177, API Stock No. H30162.
API MPMS, Chapter 9, Density Determination,    Sec.  250.1202(a)(3) and
 Section 1, Hydrometer Test Method for          (l)(4).
 Density, Relative Density (Specific
 Gravity), or API Gravity of Crude Petroleum
 and Liquid Petroleum Products, First
 Edition, June 1981, reaffirmed December
 1998, API Stock No. H30181; also available
 as ANSI/ASTM D 1298.
API MPMS, Chapter 9, Section 2, Pressure       Sec.  250.1202(a)(3) and
 Hydrometer Test Method for Density or          (l)(4).
 Relative Density, First Edition, April 1982,
 reaffirmed December 1998, API Stock No.
 H30182.
API MPMS, Chapter 10, Sediment and Water,      Sec.  250.1202(a)(3),
 Section 1, Determination of Sediment in        (l)(4).
 Crude Oils and Fuel Oils by the Extraction
 Method, First Edition, April 1981,
 reaffirmed December 1993; also available as
 ANSI/ASTM D 473, API Stock No. H30201.
API MPMS, Chapter 10, Section 2,               Sec.  250.1202(a)(3),
 Determination of Water in Crude Oil by         (l)(4).
 Distillation Method, First Edition, April
 1981, reaffirmed December 1993; also
 available as ANSI/ASTM D 4006, API Stock No.
 H30202.
API MPMS, Chapter 10, Section 3,               Sec.  250.1202(a)(3),
 Determination of Water and Sediment in Crude   (l)(4).
 Oil by the Centrifuge Method (Laboratory
 Procedure), First Edition, April 1981,
 reaffirmed December 1993; also available as
 ANSI/ASTM D 4007, API Stock No. H30203.
API MPMS, Chapter 10, Section 4,               Sec.  250.1202(a)(3),
 Determination of Sediment and Water in Crude   (l)(4).
 Oil by the Centrifuge Method (Field
 Procedure), Second Edition, May 1988,
 reaffirmed May 1998; also available as ANSI/
 ASTM D 96, API Stock No. H30204.
API MPMS, Chapter 11.1, Volume Correction      Sec.  250.1202(a)(3),
 Factors, Volume 1, Table 5A--Generalized       (g)(3) and (l)(4).
 Crude Oils and JP-4, Correction of Observed
 API Gravity to API Gravity at 60 deg.F, and
 Table 6A--Generalized Crude Oils and JP-4,
 Correction of Volume to 60 deg.F, against
 API Gravity 60 deg.F, First Edition, August
 1980, reaffirmed March 1997, API Stock No.
 H27000; also available as ANSI/ASTM D 1250.
API MPMS, Chapter 11.2.1, Compressibility      Sec.  250.1202(a)(3),
 Factors for Hydrocarbons: 0-90 deg. API        (g)(4).
 Gravity Range, First Edition, August 1984,
 reaffirmed May 1996, API Stock No. H27300.
API MPMS, Chapter 11.2.2, Compressibility      Sec.  250.1202(a)(3) and
 Factors for Hydrocarbons: 0.350-0.637          (g)(4).
 Relative Density (60 deg.F/60 deg.F) and -50
 deg.F to 140 deg.F Metering Temperature,
 Second Edition, October 1986, reaffirmed
 March 1997, API Stock No. H27307; also
 available as Gas Processors Association
 (GPA) 8286.
API MPMS, Chapter 11, Physical Properties      Sec.  250.1202(a)(3).
 Data, Addendum to Section 2.2,
 Compressibility Factors for Hydrocarbons,
 Correlation of Vapor Pressure for Commercial
 Natural Gas Liquids, First Edition, December
 1994, reaffirmed March 1997; also available
 as GPA TP-15, API Stock No. H27308.
API MPMS, Chapter 11.2.3, Water Calibration    Sec.  250.1202(f)(1).
 of Volumetric Provers, First Edition, August
 1984, reaffirmed, May 1996, API Stock No.
 H27310.
API MPMS, Chapter 12, Calculation of           Sec.  250.1202(a)(3),
 Petroleum Quantities, Section 2, Calculation   (g)(1), (g)(2).
 of Petroleum Quantities Using Dynamic
 Measurement Methods and Volumetric
 Correction Factors, Including Parts 1 and 2,
 Second Edition, May 1995; also available as
 ANSI/API MPMS 12.2-1981, API Stock No.
 H30302.
API MPMS, Chapter 14, Natural Gas Fluids       Sec.  250.1203(b)(2).
 Measurement, Section 3, Concentric Square-
 Edged Orifice Meters, Part 1, General
 Equations and Uncertainty Guidelines, Third
 Edition, September 1990, reaffirmed August
 1995; also available as ANSI/API 2530, Part
 1, 1991, API Stock No. H30350.
API MPMS, Chapter 14, Section 3, Part 2,       Sec.  250.1203(b)(2).
 Specification and Installation Requirements,
 Third Edition, February 1991, reaffirmed May
 1996, API Stock No. H30351; also available
 as ANSI/API 2530, 1991.
API MPMS, Chapter 14, Section 3, Part 3,       Sec.  250.1203(b)(2).
 Natural Gas Applications, Third Edition,
 August 1992, reaffirmed December 1998, API
 Stock No. H30353; also available as ANS/API
 2530, Part 3.
API MPMS, Chapter 14, Section 5, Calculation   Sec.  250.1203(b)(2).
 of Gross Heating Value, Relative Density,
 and Compressibility Factor for Natural Gas
 Mixtures from Compositional Analysis,
 Revised 1996; order from Gas Processors
 Association, 6526 East 60th Street, Tulsa,
 Oklahoma 74145..
API MPMS, Chapter 14, Section 6, Continuous    Sec.  250.1203(b)(2).
 Density Measurement, Second Edition, April
 1991, reaffirmed May 1998, API Stock No.
 H30346.
API MPMS, Chapter 14, Section 8, Liquefied     Sec.  250.1203(b)(2).
 Petroleum Gas Measurement, Second Edition,
 July 1997; reaffirmed May 1996, API Stock
 No. H14082.
API MPMS, Chapter 20, Section 1, Allocation    Sec.  250.1202(k)(1).
 Measurement, First Edition, September 1993,
 API Stock No. H30730.
API MPMS, Chapter 21, Section 1, Electronic    Sec.  250.1203(b)(4).
 Gas Measurement, First Edition, September
 1993, API Stock No. H30730.
API RP 2A, Recommended Practice for Planning,  Sec.  250.900(g); Sec.
 Designing and Constructing Fixed Offshore      250.912(a).
 Platforms Working Stress Design, Nineteenth
 Edition, August 1, 1991, API Stock No. 811-
 00200.
API RP 2A-WSD, Recommended Practice for        Sec.  250.900(g); Sec.
 Planning, Designing and Constructing Fixed     250.912(a).
 Offshore Platforms-Working Stress Design;
 Twentieth Edition, July 1, 1993, API Stock
 No. G00200.

[[Page 270]]

 
API RP 2A-WSD, Recommended Practice for        Sec.  250.900(g); Sec.
 Planning, Designing and Constructing Fixed     250.912(a).
 Offshore Platforms-Working Stress Design;
 Twentieth Edition, July 1, 1993, Supplement
 1, December 1996, Effective Date, February
 1, 1997, API Stock No. G00205.
API RP 2D, Recommended practice for Operation  Sec.  250.108(a)(1).
 and Maintenance of Offshore Cranes, Fourth
 Edition, August 1, 1999. API Stock No.
 G02D04.
API RP 14B, Recommended Practice for Design,   Sec.  250.801(e)(4); Sec.
 Installation, Repair and Operation of           250.804(a)(1)(i).
 Subsurface Safety Valve Systems, Fourth
 Edition, July 1, 1994, with Errata dated
 June 1996, API Stock No. G14B04.
API RP 14C, Recommended Practice for           Sec.  250.802(b), (e)(2);
 Analysis, Design, Installation and Testing     Sec.  250.803(a),
 of Basic Surface Safety Systems for Offshore   (b)(2)(i), (b)(4),
 Production Platforms, Sixth Edition, March     (b)(5)(i), (b)(7),
 1998, API Stock No. G14C06.                    (b)(9)(v), (c)(2); Sec.
                                                250.804(a), (a)(5); Sec.
                                                 250.1002(d); Sec.
                                                250.1004(b)(9); Sec.
                                                250.1628(c), (d)(2);
                                                Sec.  250.1629(b)(2),
                                                (b)(4)(v); Sec.
                                                250.1630(a).
API RP 14E, Recommended Practice for Design    Sec.  250.802(e)(3); Sec.
 and Installation of Offshore Production         250.1628(b)(2), (d)(3).
 Platform Piping Systems, Fifth Edition,
 October 1, 1991, API Stock No. G07185.
API RP 14F, Recommended Practice for Design    Sec.  250.114(c); Sec.
 and Installation of Electrical Systems for     250.803(b)(9)(v); Sec.
 Offshore Production Platforms, Third           250.1629(b)(4)(v).
 Edition, September 1, 1991, API Stock No.
 G07190.
API RP 14G, Recommended Practice for Fire      Sec.  250.803(b)(8),
 Prevention and Control on Open Type Offshore   (b)(9)(v); Sec.
 Production Platforms, Third Edition,           250.1629(b)(3),
 December 1, 1993, API Stock No. G07194.        (b)(4)(v).
API RP 14H, Recommended Practice for the       Sec.  250.802(d);
 Installation, Maintenance and Repair of        250.804(a)(4).
 Surface Safety Valves and Underwater Safety
 Valves Offshore, Fourth Edition, July 1,
 1994, API Stock No. G14H04.
API RP 500, Recommended Practice for           Sec.  250.114(a); Sec.
 Classification of Locations for Electrical     250.410(e); Sec.
 Installations at Petroleum Facilities          250.802(e)(4)(i); Sec.
 Classified as Class I, Division 1 and          250.803(b)(9)(i); Sec.
 Division 2, Second Edition, November 1997,     250.1628(b)(3);
 API Stock No. C50002.                          (d)(4)(i); Sec.
                                                250.1629(b)(4)(i).
API RP 505, Recommended Practice for           Sec.  250.114(a); Sec.
 Classification of Locations for Electrical     250.410(e); Sec.
 Installations at Petroleum Facilities          250.802(e)(4)(i); Sec.
 Classified as Class I, Zone 0, Zone 1, and     250.803(b)(9)(i); Sec.
 Zone 2, First Edition, November 1997, API      250.1628(b)(3);
 Stock No. C50501.                              (d)(4)(i); Sec.
                                                250.1629(b)(4)(i).
API RP 2556, Recommended Practice for          Sec.  250.1202(l)(4).
 Correcting Gauge Tables for Incrustation,
 Second Edition, August 1993, API Stock No.
 H25560; also available under the umbrella of
 the MPMS.
API Spec Q1, Specification for Quality         Sec.  250.806(a)(2)(ii).
 Programs for the Petroleum and Natural Gas
 Industry, Sixth Edition, March 1, 1999. API
 Stock No. GQ1006.
API Spec 6A, Specification for Wellhead and    Sec.  250.806(a)(3); Sec.
 Christmas Tree Equipment, Seventeenth           250.1002 (b)(1),
 Edition, February 1, 1996, API Stock No.       (b)(2).
 G06A17.
API Spec 6AV1, Specification for Verification  Sec.  250.806(a)(3).
 Test of Wellhead Surface Safety Valves and
 Underwater Safety Valves for Offshore
 Service, First Edition, February 1, 1996,
 API Stock No. G06AV1..
API Spec 6D, Specification for Pipeline        Sec.  250.1002(b)(1).
 Valves (Gate, Plug, Ball, and Check Valves),
 Twenty-first Edition, March 31, 1994,
 including Supplement 2, December 1, 1997,
 API Stock No. G03200.
API Spec 14A, Specification for Subsurface     Sec.  250.806(a)(3).
 Safety Valve Equipment, Ninth Edition, July
 1, 1994, API Stock No. G14A09.
API Standard 2551, Standard Method for         Sec.  250.1202(l)(4).
 Measurement and Calibration of Horizontal
 Tanks, First Edition, 1965, reaffirmed
 January 1997; API Stock No. H25510; also
 available under the umbrella of the MPMS.
API Standard 2552, Measurement and             Sec.  250.1202(l)(4).
 Calibration of Spheres and Spheroids, First
 Edition, 1966, reaffirmed January 1997, API
 Stock No. H25520; also available under the
 umbrella of the MPMS.
API Standard 2555, Method for Liquid           Sec.  250.1202(l)(4).
 Calibration of Tanks, September 1966,
 reaffirmed January 1997, API Stock No.
 H25550; also available under the umbrella of
 the MPMS.
ASTM Standard C 33-99a. Standard               Sec.  250.908(b)(4)(i).
 Specification for Concrete Aggregates.
ASTM Standard C 94/C 94M-99, Standard          Sec.  250.908(e)(2)(i).
 Specification for Ready-Mixed Concrete.
ASTM Standard C 150-99, Standard               Sec.  250.908(b)(2)(i).
 Specification for Portland Cement.
ASTM Standard C 330-99, Standard               Sec.  250.908(b)(4)(i).
 Specification for Lightweight Aggregates for
 Structural Concrete.
ASTM Standard C 595-98, Standard               Sec.  250.908(b)(2)(i).
 Specification for Blended Hydraulic Cements.
AWS D1.1-96, Structural Welding Code--Steel,   Sec.  250.907(b)(1)(i)
 1996, including Commentary.
AWS D1.4-79, Structural Welding Code--         Sec.  250.908(e)(3)(ii)
 Reinforcing Steel, 1979.
NACE Standard MR0175-99, Sulfide Stress        Sec.  250.417(p)(2).
 Cracking Resistant Metallic Materials for
 Oilfield Equipment, Revised January 1999,
 NACE Item No. 21302.
NACE Standard RP 01-76-94, Standard            Sec.  250.907(d).
 Recommended Practice, Corrosion Control of
 Steel Fixed Offshore Platforms Associated
 with Petroleum Production.
------------------------------------------------------------------------


[[Page 271]]

[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]



Sec. 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 Sec. 250.196, 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 250 subpart/title (OMB control        Reasons for collecting
                  No.)                       information and how used
------------------------------------------------------------------------
(1) Subpart A, General (1010-0114).....  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           To inform MMS, States, and the
 Development and Production Plans (1010-  public of planned exploration,
 0049).                                   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  To inform MMS of measures to be
 Control (1010-0057).                     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 Drilling      To inform MMS of the equipment
 Operations (1010-0053).                  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-         To inform MMS of the equipment
 Completion Operations (1010-0067).       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-         To inform MMS of the equipment
 Workover Operations (1010-0043).         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 G, Abandonment of Wells      To inform MMS of procedures to
 (1010-0079).                             be used during the temporary
                                          and permanent abandonment of
                                          wells. To ensure that wells
                                          are abandoned in a manner that
                                          is safe and minimizes
                                          conflicts with other uses of
                                          the OCS.

[[Page 272]]

 
(8) Subpart H, Oil and Gas Production    To inform MMS of the equipment
 Safety Systems (1010-0059).              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.
(9) Subpart I, Platforms and Structures  To provide MMS with information
 (1010-0058).                             regarding the design,
                                          fabrication, and installation
                                          of platforms on the OCS. To
                                          ensure the structural
                                          integrity of platforms
                                          installed on the OCS.
(10) Subpart J, Pipelines and Pipeline   To provide MMS with information
 Rights-of-Way (1010-0050).               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.
(11) Subpart K, Oil and Gas Production   To inform MMS of production
 Rates (1010-0041).                       rates for hydrocarbons
                                          produced on the OCS. To ensure
                                          economic maximization of
                                          ultimate hydrocarbon recovery.
(12) Subpart L, Oil and Gas Production   To inform MMS of the
 Measurement, Surface Commingling, and    measurement of production,
 Security (1010-0051).                    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.
(13) 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.
(14) Subpart N, Remedies and Penalties   The requirements in subpart N
 (1010-0121).                             are exempt from the Paperwork
                                          Reduction Act of 1995
                                          according to 5 CFR 1320.4.
(15) Subpart O, Training (1010-0078)...  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.
(16) Subpart P, Sulphur Operations       To inform MMS of sulphur
 (1010-0086).                             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.
(17) Forms MMS-123, Application for      To inform MMS of the procedures
 Permit to Drill, and MMS-123S,           and equipment to be used in
 Supplemental APD Information Sheet,      drilling operations. To ensure
 Subparts D, E, P (1010-0044 and 1010-    that drilling and well-
 0131).                                   completion are safe and
                                          protect the environment, use
                                          adequate equipment, conform
                                          with provisions of the lease,
                                          and the public is informed.
(18) Form MMS-124, Sundry Notices &      To inform MMS of well-
 Reports on Wells, Subparts D, E, F, G,   completion and well-workover
 P (1010-0045).                           operations, changes to any
                                          ongoing well operations, and
                                          well abandonment operations.
                                          To ensure that MMS has up-to-
                                          date and accurate information
                                          on OCS drilling and other
                                          lease operations; operations
                                          are safe and protect the
                                          human, marine, and coastal
                                          environment; abandoned sites
                                          are cleared of obstructions;
                                          and the public is informed.
(19) Form MMS-125, Well Summary Report,  To inform MMS of the results of
 Subparts D, E, F, P (1010-0046).         well-completion or well-
                                          workover operations or changes
                                          in well status or condition.
                                          To ensure that MMS has up-to-
                                          date and accurate information
                                          on the status and condition of
                                          wells.
(20) Form MMS-126, Well Potential Test   To inform MMS of the production
 Report, Subpart K (1010-0039).           potential of an oil or gas
                                          well and to verify a requested
                                          production rate. To ensure
                                          that production results in
                                          ultimate full recovery of
                                          hydrocarbons, and energy
                                          resources are produced at a
                                          prudent rate.
(21) Form MMS-127, Request for           To inform MMS of data
 Reservoir Maximum Efficiency Rate        concerning oil and gas well-
 (MER), Subpart K (1010-0018).            completion in a rate-sensitive
                                          reservoir and to verify
                                          requested efficiency rate. To
                                          ensure that reservoirs are
                                          classified correctly and the
                                          requested production rate will
                                          not waste oil or gas.
(22) Form MMS-128, Semiannual Well Test  To inform MMS of the status and
 Report, Subpart K (1010-0017).           capacity of gas wells and
                                          verify production capacity. To
                                          ensure that depletion of
                                          reservoirs results in greatest
                                          ultimate recovery of
                                          hydrocarbons.
(23) Form MMS-131, Performance Measures  To collect data related to a
 Data (Voluntary) (1010-0112).            set of performance measures.
                                          To evaluate the effectiveness
                                          of industry's continued
                                          improvement of safety and
                                          environmental management in
                                          the OCS.
(24) Form MMS-132, Evacuation            To inform MMS in the event of a
 Statistics (used in the GOM Region),     major disruption in the
 Subpart A (1010-0114).                   availability and supply of
                                          natural gas and oil due to
                                          natural occurrences/
                                          hurricanes. To advise the USCG
                                          of rescue needs, and to alert
                                          the news media and interested
                                          public entities when
                                          production is shut in and when
                                          resumed.
(25) Form MMS-133, Weekly Activity       To inform MMS of well status,
 Report (used in the GOM Region),         well and casing tests, and
 Subpart D (1010-0132).                   well casing configuration
                                          data. To have accurate data
                                          and information on the wells
                                          under MMS jurisdiction to
                                          ensure compliance with
                                          approved plans.
------------------------------------------------------------------------


[[Page 273]]



       Subpart B--Exploration and Development and Production Plans



Sec. 250.200  General requirements.

    All exploration, development, and production activities except for 
preliminary activities shall be conducted in accordance with an 
Exploration Plan or a Development and Production Plan approved by the 
Regional Supervisor. A proposed plan may apply to one or more leases 
held by an individual lessee or may be submitted by a group of lessees. 
The Regional Supervisor may authorize lessees to jointly submit 
environmental information for leases that are in the same planning area 
and have similar environmental conditions. Any reference in this part to 
a Development and Production Plan shall be considered to include the 
Development Operations Coordination Document used in the western Gulf of 
Mexico (GOM) (see Sec. 250.204(d)).

[53 FR 10690, Apr. 1, 1988; 53 FR 26067, July 11, 1988. Redesignated and 
amended at 63 FR 29479, 29485, May 29, 1998]



Sec. 250.201  Preliminary activities.

    Preliminary activities are geological, geophysical, and other 
surveys necessary to develop a comprehensive Exploration Plan or 
Development and Production Plan. Such preliminary activities are those 
which do not result in any physical penetration of the seabed of greater 
than 500 feet and which do not result in any significant adverse impact 
on the natural resources of the Outer Continental Shelf (OCS). The 
Regional Supervisor may require prior notification of the type, scope, 
and timing of any survey.



Sec. 250.202  Well location and spacing.

    (a) The Regional Supervisor is authorized to approve well location 
and spacing programs necessary for exploration and development of a 
leased sulphur deposit or fluid hydrocarbon reservoir giving 
consideration to, among other factors, the location of drilling units 
and platforms, extent and thickness of the sulphur deposit, geological 
and other reservoir characteristics, number of wells that can be 
economically drilled, protection of correlative rights, optimum recovery 
of resources, minimization of risk to the environment, and prevention of 
any unreasonable interference with other uses of the OCS. Well location 
and spacing programs shall be determined independently for each leased 
sulphur deposit or hydrocarbon-bearing reservoir in a manner that will 
locate wells in the optimum position for the most effective production 
of sulphur and/or reservoir fluids and avoid the drilling of unnecessary 
wells.
    (b) For wells which could intersect or drain an offset property, the 
Regional Supervisor may require special measures to protect the rights 
of the lessor and objecting offset lessees.
    (c) The lessee shall drill and produce the wells the Regional 
Supervisor determines are necessary to protect the lessor from loss by 
reason of production on other properties or in lieu thereof, with the 
approval of the Regional Supervisor, pay a sum determined by the 
Regional Supervisor as adequate to compensate the lessor for the 
lessee's failure to drill and produce any well. Payment of that sum 
shall be considered as the equivalent of production in paying quantities 
for the purpose of extending the lease term.

[53 FR 10690, Apr. 1, 1988, as amended at 55 FR 47752, Nov. 15, 1990; 56 
FR 32099, July 15, 1991. Redesignated at 63 FR 29749, May 29, 1998]



Sec. 250.203  Exploration Plan.

    (a) The leasee shall submit for approval an Exploration Plan which 
includes the following:
    (1) The proposed type and sequence of exploration activities to be 
undertaken together with a timetable for their performance from 
commencement to completion.
    (2) A description of the type of mobile drilling unit, platform, or 
artificial island to be used including a discussion of the drilling 
program and important safety and pollution-prevention features. In the 
Alaska OCS Region, lessees shall include provisions for--
    (i) Drilling a relief well should a blowout occur,
    (ii) Loss or disablement of a drilling unit, and
    (iii) Loss or damage to support craft.

[[Page 274]]

    (3) A table indicating the approximate location of each proposed 
exploratory well, including surface locations, proposed well depths, and 
water depth at well sites.
    (b) The lessee shall submit the following supporting information to 
accompany the Exploration Plan:
    (1) Data and information described below which the Regional 
Supervisor deems necessary to evaluate geologic conditions:
    (i) Current structure contour maps drawn to the top of each 
prospective hydrocarbon accumulation showing the approximate surface and 
bottomhole location of each proposed well.
    (ii) Full-scale interpreted, and if appropriate, migrated Common 
Depth Point seismic lines intersecting at or near the primary well 
locations.
    (iii) A time versus depth chart based on the appropriate velocity 
analysis in the area of interpretation.
    (iv) Interpreted structure sections corresponding to each seismic 
line submitted in paragraph (b)(1)(ii) of this section showing the 
location and proposed depth of each well.
    (v) A generalized stratigraphic column from the surface to total 
depth.
    (vi) A description of the geology of the prospect.
    (vii) A plat showing exploration seismic coverage of the lease.
    (viii) A bathymetry map showing surface locations of proposed wells.
    (ix) An analysis of seafloor and subsurface geologic and manmade 
hazards. Unless the lessee can demonstrate to the satisfaction of the 
Regional Supervisor that data sufficient to determine the presence or 
absence of such conditions are available, the lessee shall conduct a 
shallow hazards survey in accordance with the Regional Supervisor's 
specifications. The Regional Supervisor may require the submission of a 
shallow hazards report and the data upon which the analysis is based.
    (2) An oil-spill response plan as described in part 254 or reference 
to an approved Regional Response Plan.
    (3) A discussion of the measures that have been or will be taken to 
satisfy the conditions of lease stipulations.
    (4) A list of the proposed drilling fluids, including components and 
their chemical compositions, information on the projected amounts and 
rates of drilling fluid and cuttings discharges, and method of disposal.
    (5) Information concerning the presence of hydrogen sulfide 
(H2S) and the following proposed precautionary measures:
    (i) A classification of the lease area as to whether it is within an 
area known to contain H2S, an area where the presence of 
H2S is unknown, or an area where the absence of 
H2S has been confirmed as described in Sec. 250.417 of this 
part and the documentation supporting the classification; and
    (ii) If the classification is an area known to contain 
H2S or an area where the presence of H2S is 
unknown, an H2S Contingency Plan as required in Sec. 250.417 
of this part.
    (6) A detailed discussion of new or unusual technology to be 
employed. The lessee shall indicate which portions of the supporting 
information the lessee believes are exempt from disclosure under the 
Freedom of Information Act (FOIA) (5 U.S.C. 552) and the implementing 
regulations (43 CFR part 2). The lessee shall include a written 
discussion of the general subject matter of the deleted portions for 
transmittal to the recipients of plan copies.
    (7) A brief description of the onshore facilities to be used to 
support the exploration activities including information as to whether 
the facilities are existing, proposed, or are to be expanded; a brief 
description of support vessels to be used and information concerning 
their frequency of travel; and a map showing the lease relative to the 
shoreline and depicting proposed transportation routes.
    (8) For onshore support facilities, except in the western GOM, 
indicate the following:
    (i) The location, size, number, and land requirements (including 
rights-of-way and easements) of the onshore support and storage 
facilities and, where possible, a timetable for the acquisition of lands 
and the construction or expansion of any facilities.
    (ii) The estimated number of persons expected to be employed in 
support of offshore, onshore, and transportation activities and, where 
possible, the approximate number of new employees

[[Page 275]]

and families likely to move into the affected area.
    (iii) Major supplies, services, energy, water, or other resources 
within affected States necessary for carrying out the related plan.
    (iv) The source, composition, frequency, and duration of emissions 
of air pollutants.
    (9) The quantity, composition, and method of disposal of solid and 
liquid wastes and pollutants likely to be generated by offshore, 
onshore, and transportation operations.
    (10) Historic weather patterns and other meteorological conditions 
of offshore areas including temperature, sky cover and visibility, 
precipitation, storm frequency and magnitude, wind direction and 
velocity, and freezing and icing conditions listing, where possible, the 
means and extremes of each.
    (11) Physical oceanography including onsite direction and velocity 
of currents and tides, sea states, temperature, and salinity, water 
quality, and icing conditions, where appropriate.
    (12) Onsite flora and fauna including both pelagic and benthic 
communities, transitory birds and mammals that may breed or migrate 
through the area when proposed activities are being conducted, 
identification of endangered and threatened species and their critical 
habitats that could be affected by proposed activities, and typical 
fishing seasons and locations of fishing activities. The results of any 
biological surveys required by the Regional Supervisor (including a copy 
of survey reports or references to previously submitted reports) should 
be incorporated into this discussion.
    (13) Environmentally sensitive areas (onshore as well as offshore), 
e.g., refuges, preserves, sanctuaries, rookeries, calving grounds, and 
areas of particular concern identified by an affected State pursuant to 
the Coastal Zone Management Act (CZMA) which may be affected by the 
proposed activities.
    (14) Onsite uses of the area based on information available, e.g., 
shipping, military use, recreation, boating, commercial fishing, 
subsistence hunting and fishing, and other mineral exploration in the 
area.
    (15) If the Regional Director believes that an archaeological 
resource may exist in the lease area, the Regional Director will notify 
the lessee in writing. Prior to commencing any operations, the lessee 
shall prepare a report, as specified by the Regional Director, to 
determine the potential existence of any archaeological resource that 
may be affected by operations. The report shall be prepared by an 
archaeologist and geophysicist and shall be based on an assessment of 
data from remote-sensing surveys and of other pertinent archaeological 
and environmental information.
    (16) Existing and planned monitoring systems that are measuring or 
will measure environmental conditions and provide data and information 
on the impacts of activities in the geographic areas.
    (17) An assessment of the direct and cumulative effects on the 
offshore and onshore environments expected to occur as a result of 
implementation of the Exploration Plan, expressed in terms of magnitude 
and duration, with special emphasis upon the identification and 
evaluation of unavoidable and irreversible impacts on the environment. 
Measures to minimize or mitigate impacts should be identified and 
discussed.
    (18) Certificate(s) of coastal zone consistency as provided in 15 
CFR part 930.
    (19) For each OCS facility, the lessee shall submit the information 
described below when it is needed to make the findings under 
Sec. 250.303 or Sec. 250.304 of this part:
    (i)(A) Projected emissions from each proposed or modified facility 
for each year of operation and the basis for all calculations to include 
(if the drilling unit has not yet been determined, the lessee shall use 
worst-case estimates for the type of unit proposed):
    (1) For each source, the amount of the emission by air pollutant 
expressed in tons per year and the frequency and duration of emissions.
    (2) For each facility, the total amount of emissions by air 
pollutant expressed in tons per year and, in addition for a modified 
facility only, the incremental amount of total emissions by air 
pollutant resulting from the new or modified source(s).

[[Page 276]]

    (3) A detailed description of all processes, processing equipment, 
and storage units, including information on fuels to be burned.
    (4) A schematic drawing which identifies the location and elevation 
of each source.
    (5) If projected emissions are based on the use of emission-
reduction control technology, a description of the controls providing 
the information required by paragraph (b)(19)(iv) of this section.
    (B) The distance of each proposed facility from the mean high water 
mark (mean higher high water mark on the Pacific coast) of any State.
    (ii)(A) The model(s) used to determine the effect on the onshore air 
quality of emissions from each facility, or from other facilities when 
required by the Regional Supervisor, and the results obtained through 
the use of the model(s). Only model(s) that has been approved by the 
Director may be used.
    (B) The best available meteorological information and data 
consistent with the model(s) used stating the basis for the data and 
information selected.
    (iii) The air quality status of any onshore area where the air 
quality is significantly affected (within the meaning of Sec. 250.303 of 
this part) by projected emissions from each facility proposed in the 
plan. The area should be classified as nonattainment, attainment, or 
unclassifiable to include the status of each area by air pollutant, the 
class of attainment area, and the air-pollution control agency whose 
jurisdiction covers the area identified.
    (iv) The emission-reduction controls available to reduce emissions, 
including the source, the emission-reduction control technology, 
reductions to be achieved, and monitoring system the lessee proposes to 
use to measure emissions. The lessee shall indicate which emission-
reduction control technology the lessee believes constitutes the best 
available control technology and the basis for that opinion.
    (20) The name, address, and telephone number of an individual 
employee of the lessee to whom inquiries by the Regional Supervisor and 
the affected State(s) may be made.
    (21) Such other information and data as the Regional Supervisor may 
require.
    (c) Information and data discussed in other documents previously 
submitted to MMS or otherwise readily available to reviewers may be 
referenced. The material being referenced shall be cited, described 
briefly, and include a statement of where the material is available for 
inspection. Any material based on proprietary data which is not itself 
available for inspection shall not be so referenced.
    (d) The Regional Director, after consultation with the Governor of 
the affected State(s) or the Governor's designated representative, the 
CZM agency of affected State(s), and the Office of Ocean and Coastal 
Resource Management of the National Oceanic and Atmospheric 
Administration (NOAA) may limit the amount of information required to be 
included to that necessary to assure conformance with the Act, other 
laws, applicable regulations, and lease provisions.
    (e) The Regional Supervisor shall determine within 10 working days 
after receipt of the Exploration Plan whether additional information is 
needed. If no deficiencies are identified and the required number of 
copies have been received, the plan will be deemed submitted.
    (f) Within 2 working days after we deem the Exploration Plan 
submitted, the Regional Supervisor will send by receipted mail a copy of 
the plan (except those portions exempt from disclosure under the Freedom 
of Information Act and 43 CFR part 2) to the Governor or the Governor's 
designated representative and the CZM agency of each affected State. 
Consistency review begins when the State's CZM agency receives a copy of 
the deemed submitted plan, consistency certification, and required 
necessary data and information as directed by 15 CFR 930.78.
    (g) In accordance with the National Environmental Policy Act (NEPA), 
the Regional Supervisor shall evaluate the environmental impacts of the 
activities described in the Exploration Plan.
    (h) In the evaluation of an Exploration Plan, the Regional 
Supervisor shall consider written comments from

[[Page 277]]

the Governor of an affected State or the Governor's designated 
representative which are received prior to the deadline specified by the 
Regional Supervisor. The Regional Supervisor may consult directly with 
affected States regarding matters contained in the comments.
    (i) Within 30 days of submission of a proposed Exploration Plan, the 
Regional Supervisor shall accomplish one of the following:
    (1) Approve the plan;
    (2) Require the lessee to modify any plan which is inconsistent with 
the provisions of the lease, the Act, or the regulations prescribed 
under the Act including air quality, environmental, safety, and health 
requirements; or
    (3) Disapprove the plan if the Regional Supervisor determines that a 
proposed activity would probably cause serious harm or damage to life 
(including fish and other aquatic life), property, natural resources 
offshore including any mineral deposits (in areas leased or not leased), 
the national security or defense, or the marine, coastal, or human 
environment, and that the proposed activity cannot be modified to avoid 
the condition(s).
    (j) The Regional Supervisor shall notify the lessee in writing of 
the reason(s) for disapproving an Exploration Plan or for requiring 
modification of a plan. For plans requiring modification, the Regional 
Supervisor shall also notify the lessee in writing of the conditions 
that must be met for plan approval.
    (k)(1) The lessee may resubmit an Exploration Plan, as modified, to 
the Regional Supervisor in the same manner as for a new plan. Only 
information related to the proposed modifications need be submitted. The 
Regional Supervisor shall approve, disapprove, or require modification 
of the resubmitted plan based upon the criteria in paragraph (i) of this 
section within 30 days of the resubmission date.
    (2) An Exploration Plan which has been disapproved pursuant to 
paragraph (i)(3) of this section may be resubmitted if there is a change 
in the conditions which caused it to be disapproved. The Regional 
Supervisor shall approve, require modification, or disapprove such a 
plan within 30 days of the resubmission date.
    (l) When a State objects to a lessee's coastal zone consistency 
certification, the lessee shall modify the plan to accommodate the 
State's objection(s) and resubmit the plan to--
    (1) The Regional Supervisor for review pursuant to the criteria in 
paragraphs (h), (i), and (j) of this section; and
    (2) Through the Regional Supervisor to the State for review pursuant 
to the CZMA and the implementing regulations (15 CFR 930.83 and 930.84).

Alternatively, the lessee may appeal the State's objection to the 
Secretary of Commerce pursuant to the procedures described in section 
307 of the CZMA and the implementing regulations (subpart H of 15 CFR 
part 930). The Regional Supervisor shall approve or disapprove a plan as 
resubmitted within 30 days of the resubmission date.
    (m) If the Regional Supervisor disapproves an Exploration Plan, the 
Secretary may, subject to the provisions of section 5(a)(2)(B) of the 
Act and the implementing regulations in Sec. 250.182 and 256.77 of this 
chapter II, cancel the lease(s), and the lessee shall be entitled to 
compensation in accordance with section 5(a)(2)(c) of the Act.
    (n)(1) The Regional Supervisor shall periodically review the 
activities being conducted under an approved Exploration Plan and may 
request updated information on schedules and procedures. The frequency 
and extent of the Regional Supervisor's review shall be based upon the 
significance of any changes in available information and in other 
onshore or offshore conditions affecting or affected by exploration 
activities being conducted pursuant to the plan. If the review indicates 
that the plan should be revised to meet the requirements of this part, 
the Regional Supervisor shall require the needed revision.
    (2) Revisions to an approved or pending Exploration Plan, whether 
initiated by the lessee or ordered by the Regional Supervisor, shall be 
submitted to the Regional Supervisor for approval. Only information 
related to the proposed revisions need be submitted.

[[Page 278]]

When the Regional Supervisor determines that a proposed revision could 
result in a significant change in the impacts previously identified and 
evaluated or requires additional permits, the revisions shall be subject 
to all of the procedures in this section.
    (o) To ensure safety and protection of the environment and 
archaeological resources, the Regional Director may authorize or direct 
the lessee to conduct geological, geophysical, biological, 
archaeological, or other surveys or monitoring programs. The lessee 
shall provide the Regional Director, upon request, with copies of any 
data obtained as a result of those surveys and monitoring programs.
    (p) The lessee may not drill any well until the District 
Supervisor's approval of an Application for Permit to Drill (APD), 
submitted in accordance with the requirements of Sec. 250.414 of this 
part, has been received. The District Supervisor shall not approve any 
APD until all affected States with approved CZM programs have concurred 
or have been conclusively presumed to concur with the applicant's 
coastal zone consistency certification accompanying a plan, or the 
Secretary of Commerce has made the finding authorized by section 
307(c)(3)(B)(iii) of the CZMA. The APD's must conform to the activities 
described in detail in the approved Exploration Plan and shall not be 
subject to a separate State coastal zone consistency review.
    (q) Nothing in this section or in an approved plan shall limit the 
lessee's responsibility to take appropriate measures to meet emergency 
situations. In such situations, the Regional Supervisor may approve or 
require departures from an approved Exploration Plan.

[53 FR 10690, Apr. 1, 1988; 53 FR 26067, July 11, 1988, as amended at 54 
FR 50616, Dec. 8, 1989; 59 FR 53093, Oct. 21, 1994; 62 FR 13996, Mar. 
25, 1997. Redesignated and amended at 63 FR 29479, 29485, May 29, 1998; 
64 FR 53200, Oct. 1, 1999; 64 FR 72794, Dec. 28, 1999]



Sec. 250.204  Development and Production Plan.

    (a) The lessee shall submit for approval a Development and 
Production Plan which includes the following:
    (1) A description of and schedule for the development and production 
activities to be performed including plan commencement date, date of 
first production, total time to complete all development and production 
activities, and dates and sequences for drilling wells and installing 
facilities and equipment.
    (2) A description of any drilling vessels, platforms, pipelines, or 
other facilities and operations located offshore which are proposed or 
known by the lessee (whether or not owned or operated by the lessee) to 
be directly related to the proposed development, including the location, 
size, design, and important safety, pollution prevention, and 
environmental monitoring features of the facilities and operations.
    (b) The lessee shall submit the following supporting information to 
accompany the Development and Production Plan:
    (1) Geological and geophysical (G&G) data and information, including 
the following:
    (i) A plat showing the surface location of any proposed fixed 
structure or well.
    (ii) A plat showing the surface and bottomhole locations and giving 
the measured and true vertical depths for each proposed well.
    (iii) Current interpretations of relevant G&G data.
    (iv) Current structure map(s) showing the surface and bottomhole 
location of each proposed well and the depths of expected productive 
formations.
    (v) Interpreted structure sections showing the depths of expected 
productive formations.
    (vi) A bathymetric map showing surface locations of fixed structures 
and wells or a table of water depths at each proposed site.
    (vii) A discussion of seafloor conditions including a shallow 
hazards analysis for proposed drilling and platform sites and pipeline 
routes. This information shall be derived from the shallow hazards 
report required by Sec. 250.909 of this part.
    (2) Information concerning the presence of H2S and 
proposed precautionary measures, including the following:

[[Page 279]]

    (i) A classification of the lease area as to whether it is within an 
area known to contain H2S, an area where the presence of 
H2S is unknown, or an area where the absence of 
H2S has been confirmed as described in Sec. 250.417 of this 
part and the documentation supporting the classification; or
    (ii) If the classification is an area known to contain 
H2S or an area where the presence of H2S is 
unknown, an H2S Contingency Plan as required in Sec. 250.417 
of this part.
    (3) A description of the environmental safeguards to be implemented, 
including an updated oil-spill response plan as described in part 254 of 
this chapter or reference to an approved plan.
    (4) A discussion of the steps that have been or will be taken to 
satisfy the conditions of lease stipulations.
    (5)(i) A description of technology and reservoir engineering 
practices intended to increase the ultimate recovery of oil and gas, 
i.e., secondary, tertiary, or other enhanced recovery practices;
    (ii) A description of technology and recovery practices and 
procedures intended to assure optimum recovery of sulphur; or
    (iii) A description of technology and recovery practices and 
procedures intended to assure optimum recovery of oil and gas and 
sulphur.
    (6) A discussion of the proposed drilling and completion programs.
    (7) A detailed description of new or unusual technology to be 
employed. The lessee shall indicate which portions of the information 
the lessee believes are exempt from disclosure under the FOIA (5 U.S.C. 
552) and the implementing regulations (43 CFR part 2). The lessee shall 
include a written discussion of the general subject matter of the 
deleted portions for transmittal to recipients of plan copies.
    (8) A brief description of the following:
    (i) The location, description, and size of any offshore, and to the 
maximum extent practicable, land-based operations to be conducted or 
contracted for as a result of the proposed activity, including the 
following:
    (A) The acreage required within a State for facilities, rights-of-
way, and easements.
    (B) The means proposed for transportation of oil, gas, and sulphur 
to shore; the routes to be followed by each mode of transportation; and 
the estimated quantities of oil, gas, and sulphur to be moved along such 
routes.
    (C) An estimate of the frequency of boat and aircraft departures and 
arrivals, the onshore location of terminals, and the normal routes for 
each mode of transportation.
    (ii) A list of the proposed drilling fluids including components and 
their chemical compositions, information on the projected amounts and 
rates of drilling fluid and cuttings discharges, and method of disposal. 
If the information is provided in an approved Environmental Protection 
Agency, National Pollutant Discharge Elimination System permit, or a 
pending permit application, the lessee may reference these documents.
    (iii) The quantities, types, and plans for disposal of other solid 
and liquid wastes and pollutants likely to be generated by offshore, 
onshore, and transport operations and, regarding any wastes which may 
require onshore disposal, the means of transportation to be used to 
bring the wastes to shore, disposal methods to be utilized, and location 
of onshore waste disposal or treatment facilities.
    (iv) The following information on onshore support facilities, except 
in the western GOM:
    (A) The approximate number, timing, and duration of employment of 
persons who will be engaged in onshore development and production 
activities, an approximate number of local personnel who will be 
employed for or in support of the development activities (classified by 
the major skills or crafts that will be required from local sources and 
estimated number of each such skill needed), and the approximate total 
number of persons who will be employed during the onshore construction 
activity and during all activities related to offshore development and 
production.

[[Page 280]]

    (B) The approximate number of people and families to be added to the 
population of local nearshore areas as a result of the planned 
development.
    (C) An estimate of significant quantities of energy and resources to 
be used or consumed including electricity, water, oil and gas, diesel 
fuel, aggregate, or other supplies which may be purchased within an 
affected State.
    (D) The types of contractors or vendors which will be needed, 
although not specifically identified, and which may place a demand on 
local goods and services.
    (E) The source, composition, frequency, and duration of emissions of 
air pollutants.
    (v) A narrative description of the existing environment with an 
emphasis placed on those environmental values that may be affected by 
the proposed action. This section shall contain a description of the 
physical environment of the area covered by the related plan. This 
portion of the plan shall include data and information obtained or 
developed by the lessee together with other pertinent information and 
data available to the lessee from other sources. The environmental 
information and data shall include the following, where appropriate:
    (A) If the Regional Director believes that an archaeological 
resource may exist in the lease area, the Regional Director will notify 
the lessee in writing. Prior to commencing any operations, the lessee 
shall prepare a report, as specified by the Regional Director, to 
determine the potential existence of any archaeological resource that 
may be affected by operations. The report shall be prepared by an 
archaeologist and geophysicist and shall be based on an assessment of 
data from remote-sensing surveys and of other pertinent archaeological 
and environmental information.
    (B) The aquatic biota, including a description of fishery and marine 
mammal use of the lease and the significance of the lease, and a 
description of any threatened and endangered species and their critical 
habitat. The results of any biological surveys required by the Regional 
Supervisor (including a copy of survey reports or references to 
previously submitted reports) should be incorporated into these 
discussions.
    (C) Environmentally sensitive areas (e.g., refuges, preserves, 
sanctuaries, rookeries, calving grounds, coastal habitat, beaches, and 
areas of particular environmental concern) which may be affected by the 
proposed activities.
    (D) The predevelopment, ambient water-column quality and temperature 
data for incremental depths for the areas encompassed by the plan.
    (E) The physical oceanography, including ocean currents described as 
to prevailing direction, seasonal variations, and variations at 
different water depths in the lease.
    (F) Historic weather patterns and other meteorological conditions, 
including storm frequency and magnitude, wave height and direction, wind 
direction and velocity, air temperature, visibility, freezing and icing 
conditions, and ambient air quality listing, where possible, the means 
and extremes of each.
    (G) The other uses of the area known to the lessee, including 
military use for national security or defense, subsistence hunting and 
fishing, commercial fishing, recreation, shipping, and other mineral 
exploration or development.
    (H) The existing or planned monitoring systems that are measuring or 
will measure impacts of activities on the environment in the planning 
area.
    (9) For sulphur operations, the degree of subsidence that is 
expected at various stages of production, and measures that will be 
taken to assure safety of operations and protection of the environment. 
Special attention shall be given to the effects of subsidence on 
existing or potential oil and gas production, fixed bottom-founded 
structures, and pipelines.
    (10) For sulphur operations, a discussion of the potential toxic or 
thermal effects on the environment caused by the discharge of 
bleedwater, including a description of the measures that will be taken 
into account to mitigate these impacts.
    (11) An assessment of the effects on the environment expected to 
occur as a result of implementation of the plan, identifying specific 
and cumulative impacts that may occur both onshore and

[[Page 281]]

offshore, and the measures proposed to mitigate these impacts. Such 
impacts shall be quantified to the fullest extent possible including 
magnitude and duration and shall be accumulated for all activities for 
each of the major elements of the environment (e.g., water or biota).
    (12) A discussion of alternatives to the activities proposed that 
were considered during the development of the plan including a 
comparison of the environmental effects.
    (13) Certificate(s) of coastal zone consistency as provided in 15 
CFR part 930.
    (14) For each OCS facility, such information described below needed 
to make the findings under Sec. 250.303 or Sec. 250.304 of this part:
    (i)(A) Projected emissions from each proposed or modified facility 
for each year of operation and basis for all calculations to include the 
following:
    (1) For each source, the amount of the emission by air pollutant 
expressed in tons per year and frequency and duration of emissions;
    (2) For each proposed facility, the total amount of emissions by air 
pollutant expressed in tons per year, the frequency distribution of 
total emissions by air pollutant expressed in pounds per day and, in 
addition for a modified facility only, the incremental amount of total 
emissions by air pollutant resulting from the new or modified source(s);
    (3) A detailed description of all processes, processing equipment, 
and storage units, including information on fuels to be burned;
    (4) A schematic drawing which identifies the location and elevation 
of each source; and
    (5) If projected emissions are based on the use of emission-
reduction control technology, a description of the controls providing 
the information required by paragraph (b)(12)(iv)(A) of this section.
    (B) The distance of each proposed facility from the mean high water 
mark (mean higher high water mark on the Pacific coast) of any State.
    (ii)(A) The model(s) used to determine the effect on the onshore air 
quality of emissions from each facility, or from other facilities when 
required by the Regional Supervisor, and the result obtained through the 
use of the model(s). Only model(s) that has been approved by the 
Director may be used.
    (B) The best available meteorological information and data 
consistent with the model(s) used stating the basis for the information 
and data selected.
    (iii) The air quality status of any onshore area where the air 
quality is significantly affected (within the meaning of Sec. 250.303 of 
this part) by projected emissions from each facility proposed in the 
plan. The area should be classified as nonattainment, attainment, or 
unclassifiable listing the status of each area by air pollutant, the 
class of attainment areas, and the air pollution control agency whose 
jurisdiction covers the area identified.
    (iv)(A) The emission-reduction controls available to reduce 
emissions including the source, emission-reduction control technology, 
reductions to be achieved, and monitoring system the lessee proposes to 
use to measure emissions. The lessee shall indicate which emission-
reduction control technology the lessee believes constitutes the best 
available control technology and the basis for that opinion.
    (B) The ownership of the offshore and onshore offsetting source(s) 
and the reduction obtainable from each offsetting source.
    (15) A brief discussion of any approved or anticipated suspensions 
of production necessary to hold the lease(s) in an active status.
    (16) The name, address, and telephone number of an individual 
employee of the lessee to whom inquiries by the Regional Supervisor and 
the affected State(s) may be directed.
    (17) Such other data and information as the Regional Supervisor may 
require.
    (c) Data and information discussed in other documents previously 
submitted to MMS or otherwise readily available to reviewers may be 
incorporated by reference. The material being incorporated shall be 
cited and described briefly and include a statement of where the 
material is available for inspection. Any material based on proprietary 
data which is not itself available for inspection shall not be 
incorporated by reference.

[[Page 282]]

    (d)(1) Development and Production Plans are not required for leases 
in the western GOM. For these leases, the lessee shall submit to the 
Regional Supervisor for approval a Development Operations Coordination 
Document with all information necessary to assure conformance with the 
Act, other laws, applicable regulations, lease provisions, or as 
otherwise needed to carry out the functions and responsibilities of the 
Regional Supervisor.
    (2) Any information required in paragraph (d)(1) of this section 
shall be considered a Development and Production Plan for the purpose of 
references in any law, regulation, lease provision, agreement, or other 
document referring to the preparation or submission of a plan.
    (e) The Regional Director, after consultation with the Governor(s) 
of the affected State(s) or the Governor's designated representative, 
the CZM agency of the affected State(s), and the Office of Ocean and 
Coastal Resource Management of NOAA may limit the amount of information 
required to be included in a Development and Production Plan to that 
necessary to assure conformance with the Act, other laws, applicable 
regulations, and lease provisions. In determining the information to be 
included in a plan, the Regional Director shall consider current and 
expected operating conditions together with experience gained during 
past operations of a similar nature in the area of proposed activities.
    (f) The Regional Supervisor shall determine within 20 working days 
after receipt whether additional material is needed. If no deficiencies 
are identified and the requested number of copies have been received, 
the plan shall be deemed submitted.
    (g) Within 5 working days after a Development and Production Plan 
has been deemed submitted, the Regional Supervisor shall transmit a copy 
of the plan, except for those portions of the plan determined to be 
exempt from disclosure under the FOIA and the implementing regulations 
(43 CFR part 2), to the Governor or the Governor's designated 
representative and the CZM agency of each affected State and to the 
executive of each affected local government that requests a copy. The 
Regional Supervisor shall make copies available to appropriate Federal 
Agencies, interstate entities, and the public. The plan will be 
available for review at the appropriate MMS Regional Public Information 
Office.
    (h) The Governor or the Governor's designated representative and the 
CZM agency of each affected State and the executive of each affected 
local government shall have 60 days from the date of receipt of the 
Development and Production Plan to submit comments and recommendations 
to the Regional Supervisor. The executive of any affected local 
government must forward all recommendations to the Governor of the State 
prior to submitting them to the Regional Supervisor. The Regional 
Supervisor shall accept those recommendations from the Governor that 
provide for a reasonable balance between the national interest and the 
well-being of the citizens of the affected State. The Regional 
Supervisor shall explain in writing the reasons for accepting or 
rejecting any recommendations. In addition, any interested Federal 
Agency or person may submit comments and recommendations to the Regional 
Supervisor. All comments and recommendations shall be made available to 
the public.
    (i) We will process the plan according to this section and 15 CFR 
part 930. Accordingly, consistency review begins when the State's CZM 
agency receives a copy of the deemed submitted plan, consistency 
certification, and required necessary data and information as directed 
by 15 CFR 930.78.
    (j) The Regional Supervisor will evaluate the environmental impact 
of the activities described in the Development and Production Plan (DPP) 
and prepare the appropriate environmental documentation required by the 
National Environmental Policy Act of 1969. At least once in each 
planning area (other than the western and central Gulf of Mexico 
planning areas), we will prepare an environmental impact statement (EIS) 
and send copies of the draft EIS to the Governor of each affected State 
and the executive of each affected local government that requests a 
copy. Additionally, when we prepare a DPP EIS and when the State's 
federally approved coastal

[[Page 283]]

management program requires a DPP NEPA document for use in determining 
consistency, we will forward a copy of the draft EIS to the State's CZM 
Agency. We will also make copies of the draft EIS available to any 
appropriate Federal Agency, interstate entity, and the public.
    (k) Prior to or immediately after a determination by the Director 
that approval of a Development and Production Plan requires that the 
procedures under NEPA shall commence, the Regional Supervisor may 
require lessees of tracts in the vicinity, for which Development and 
Production Plans have not been approved, to submit preliminary or final 
plans for their leases.
    (l) No later than 60 days after the last day of the comment period 
provided in paragraph (h) of this section or within 60 days of the 
release of the final EIS describing the proposed activities, the 
Regional Supervisor shall accomplish the following:
    (1) Approve the plan;
    (2) Require modification of the plan if it is determined that the 
lessee has failed to make adequate provisions for safety, environmental 
protection, or conservation of resources including compliance with the 
regulations prescribed under the Act; or
    (3) Disapprove the plan if one or more of the following occurs:
    (i) The lessee fails to demonstrate that compliance with the 
requirements of the Act, provisions of the regulations prescribed under 
the Act, or other applicable Federal laws is possible;
    (ii) State concurrence with the applicant's coastal zone consistency 
certification has not been received, the State's concurrence has not 
been conclusively presumed, or the State objects to the consistency 
certification, and the Secretary of Commerce does not make the 
determination authorized by section 307(c)(3)(B)(iii) of the CZMA;
    (iii) Operations threaten national security or defense; or
    (iv) Exceptional geological conditions in the lease area, 
exceptional resource value in the marine or coastal environment, or 
other exceptional circumstances exist, and all of the following:
    (A) Implementation of the plan would probably 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 to the marine, coastal, or human environments.
    (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 disapproving the plan outweigh the advantages 
of development and production.
    (m) The Regional Supervisor shall notify the lessee in writing of 
the reason(s) for disapproving a Development and Production Plan or for 
requiring modification of a plan and the conditions which must be met 
for plan approval.
    (n) The lessee may resubmit a Development and Production Plan, as 
modified, to the Regional Supervisor. Only information related to the 
proposed modifications need be submitted. Within 60 days following the 
60-day comment period provided for in paragraph (h) of this section, the 
Regional Supervisor shall approve, disapprove, or require modification 
of the modified plan.
    (o)(1) If a Development and Production Plan is disapproved for the 
sole reason that a State consistency certification has not been 
obtained, the Regional Supervisor shall approve the plan upon receipt of 
the concurrence, at the time when concurrence is conclusively presumed, 
or when the Secretary of Commerce makes a finding authorized by section 
307(c)(3)(B)(iii) of the CZMA.
    (2) If a Development and Production Plan is disapproved because a 
State objects to the lessee's coastal zone consistency certification, 
the lessee shall modify the plan to accommodate the State's objection(s) 
and resubmit the plan to (i) the Regional Supervisor for review pursuant 
to the criteria in paragraph (l) of this section; and (ii) through the 
Regional Supervisor, to the State for review pursuant to the CZMA and 
the implementing regulations (15 CFR 930.83 and 930.84). Alternatively, 
the lessee may appeal the State's objection to the Secretary of

[[Page 284]]

Commerce pursuant to the procedures described in section 307 of the CZMA 
and the implementing regulations (subpart H of 15 CFR part 930). The 
Regional Supervisor shall approve, disapprove, or require modification 
of a plan as revised within 60 days following the 60-day comment period 
provided for in paragraph (h) of this section.
    (p) Development and Production Plans disapproved pursuant to 
paragraph (l)(3) of this section are subject to the provisions of 
section 25(h)(2) of the Act and the implementing regulations in 
Secs. 250.183 and 256.77 of this chapter.
    (q)(1) The Regional Supervisor shall periodically review the 
activities being conducted under an approved Development and Production 
Plan. The frequency and extent of the Regional Supervisor's review shall 
be based upon the significance of any changes in available information 
and onshore or offshore conditions affecting or impacted by development 
or production activities being conducted pursuant to the plan. If the 
review indicates that the plan should be revised to meet the 
requirements of this part, the Regional Supervisor shall require the 
needed revisions.
    (2) Revisions to an approved or pending Development and Production 
Plan, whether initiated by the lessee or ordered by the Regional 
Supervisor, shall be submitted to the Regional Supervisor for approval. 
Only information related to the proposed revisions need be submitted. 
When the Regional Supervisor determines that a proposed revision could 
result in a significant change in the impacts previously identified and 
evaluated, requires additional permits, or proposes activities not 
previously identified and evaluated, the revision shall be subject to 
all of the procedures in this section.
    (3) When any revision to an approved Development and Production Plan 
is proposed by the lessee, the Regional Supervisor may approve the 
revision if it is determined that the revision is consistent with the 
protection of the marine, coastal, and human environments and will lead 
to greater recovery of oil and natural gas; will improve the efficiency, 
safety, and environmental protection of the recovery operation; is the 
only means available to avoid substantial economic hardship to the 
lessee; or is otherwise not inconsistent with the provisions of the Act.
    (r) Whenever the lessee fails to submit a Development and Production 
Plan in accordance with provisions of this section or fails to comply 
with an approved plan, the lease may be cancelled in accordance with 
sections 5 (c) and (d) of the Act and the implementing regulations in 
Secs. 250.183 and 256.77 of this chapter.
    (s) To ensure safety and protection of the environment and 
archaeological resources, the Regional Director may authorize or direct 
the lessee to conduct geological, geophysical, biological, 
archaeological, or other surveys or monitoring programs. The lessee 
shall provide the Regional Director, upon request, copies of any data 
obtained as a result of those surveys and monitoring programs.
    (t) The lessee may not drill any well until the District 
Supervisor's approval of an APD, filed in accordance with the 
requirements of Sec. 250.414 of this part, has been received. All APD's 
and applications to install platforms and structures, pipelines, and 
production equipment must conform to the activities described in detail 
in the approved Development and Production Plan and shall not be subject 
to a separate State coastal zone consistency review.
    (u) Nothing in this section or approved plans shall limit the 
lessee's responsibility to take appropriate measures to meet emergency 
situations. In such situations, the Regional Supervisor may approve or 
require departures from an approved Development and Production Plan.

[53 FR 10690, Apr. 1, 1988; 53 FR 26067, July 11, 1988, as amended at 54 
FR 50616, Dec. 8, 1989; 55 FR 47752, Nov. 15, 1990; 56 FR 32099, July 
15, 1991; 59 FR 53093, Oct. 21, 1994; 62 FR 13996, Mar. 25, 1997. 
Redesignated and amended at 63 FR 29479, 29485, May 29, 1998; 64 FR 
9065, Feb. 24, 1999; 64 FR 53200, Oct. 1, 1999; 64 FR 72794, Dec. 28, 
1999]



               Subpart C--Pollution Prevention and Control



Sec. 250.300  Pollution prevention.

    (a) During the exploration, development, production, and 
transportation

[[Page 285]]

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 Supervisor 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 Supervisor.
    (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 Supervisor may restrict the rate of drilling 
fluid discharges or prescribe alternative discharge methods. The 
District Supervisor 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 Supervisor.
    (2) Approval of the method of disposal of drill cuttings, sand, and 
other well solids shall be obtained from the District Supervisor.
    (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

[[Page 286]]

    (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 Supervisor.

[53 FR 10690, Apr. 1, 1988, as amended at 56 FR 32099, July 15, 1991. 
Redesignated at 63 FR 29479, May 29, 1998]



Sec. 250.301  Inspection of facilities.

    (a) Drilling and production facilities shall be inspected daily or 
at intervals approved or prescribed by the District Supervisor 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]



Sec. 250.302  Definitions concerning air quality.

    For purposes of Secs. 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.

[[Page 287]]

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]



Sec. 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 Sec. 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 Sec. 250.203(b)(19) 
or Sec. 250.204(b)(12) 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 Sec. 250.203(b)(19)(i)(A) or 
Sec. 250.204(b)(12)(i)(A) of this part and compare these emissions to 
the emission exemption amount ``E'' for each air pollutant calculated 
using the following formulas: E=3400D2/3 for carbon monoxide 
(CO); and E=33.3D for total suspended particulates (TSP), sulphur 
dioxide (SO2), nitrogen oxides (NOx), and VOC 
(where E is the emission exemption amount expressed in tons per year, 
and D is the distance of the proposed facility from the closest onshore 
area of a State expressed in statute miles). If the amount of these 
projected emissions is less than or equal to the emission exemption 
amount ``E'' for the air pollutant, the facility is exempt from further 
air quality review required under paragraphs (e) through (i) of this 
section.
    (e) Significance levels. For a facility not exempt under paragraph 
(d) of this section for air pollutants other than VOC, the lessee shall 
use an approved air quality model to determine whether the projected 
emissions of those air pollutants from the facility result in an onshore 
ambient air concentration above the following significance levels:

   Significance Levels: Air pollutant concentrations (g/m\3\)
------------------------------------------------------------------------
                                               Averaging time (hours)
               Air pollutant               -----------------------------
                                             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

[[Page 288]]

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 (g/m\3\)
------------------------------------------------------------------------
                                                    Averaging times
                                             ---------------------------
                Air pollutant                  Annual   24-hour   3-hour
                                              mean \1\  maximum  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

[[Page 289]]

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]



Sec. 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 Sec. 250.203(b)(19) or 250.204(b)(12) 
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

[[Page 290]]

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 Sec. 250.203(b)(19)(i)(A) or 
250.204(b)(12)(i)(A) of this part and compare these emissions to the 
emission exemption amount ``E'' for each air pollutant calculated using 
the following formulas: E=3400D2/3 for CO; and E=33.3D for 
TSP, SO2, NOX, and VOC (where E is the emission 
exemption amount expressed in tons per year, and D is the distance of 
the facility from the closest onshore area of the State expressed in 
statute miles). If the amount of projected emissions is less than or 
equal to the emission exemption amount ``E'' for the air pollutant, the 
facility is exempt for that air pollutant from further air quality 
review required under paragraphs (c) through (e) of this section.
    (c) Significance levels. For a facility not exempt under paragraph 
(b) of this section for air pollutants other than VOC, the lessee shall 
use an approved air quality model to determine whether projected 
emissions of those air pollutants from the facility result in an onshore 
ambient air concentration above the following significance levels:

   Significance Levels: Air Pollutant Concentrations (G/M\3\)
------------------------------------------------------------------------
                                               Averaging time (hours)
               Air pollutant               -----------------------------
                                             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 Sec. 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,

[[Page 291]]

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]



               Subpart D--Oil and Gas Drilling Operations



Sec. 250.400  Control of wells.

    The lessee shall take necessary precautions to keep its wells under 
control at all times. The lessee shall utilize the best available and 
safest drilling technology in order to enhance the evaluation of 
conditions of abnormal pressure and to minimize the potential for the 
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.



Sec. 250.401  General requirements.

    (a) Fitness of drilling unit. (1) Drilling units shall be capable of 
withstanding the oceanographic, meteorological, and ice conditions for 
the proposed season and location of operations.
    (2) Prior to commencing operation, drilling units shall be available 
for complete inspection by the District Supervisor.
    (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 
Sec. 250.414. The District Supervisor may require the submission of a 
third-party review of the design of drilling units which are of a unique 
design and/or not proven for use in the proposed environment if the 
District Supervisor believes that the information submitted by the 
lessee is insufficient to demonstrate suitability of the unit for use at 
the proposed drill site. A design Certified Verification Agent approved 
in accordance with Sec. 250.903 of this part shall be used for any 
required third-party review.
    (b) Drilling unit safety devices. (1) No later than May 31, 1989, 
all drilling units 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 driller's report.
    (2) 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.
    (c) Oceanographic, meteorological, and drilling unit performance 
data. Where such information is not otherwise readily available, upon 
request of the District Supervisor, lessees shall collect and report 
oceanographic, meteorological, and drilling unit performance data, and 
monitor ice conditions, if applicable, during the period of operations. 
The type of information to be collected and reported will be determined 
by the District Supervisor in the interests of safe conduct of 
operations and the structural integrity of the drilling unit.
    (d) Foundation requirements. When the lessee fails to provide 
sufficient information pursuant to Secs. 250.203 and 250.204 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 Supervisor may 
require that additional surveys and soil borings be performed and the 
results be submitted for review and evaluation by the District 
Supervisor before approval is granted for commencing drilling 
operations.
    (e) Tests, surveys, and samples. (1) The lessee shall conduct tests, 
obtain well and mud logs or surveys, and take samples to determine the 
reservoir energy; the presence, quantity, and quality of oil, gas, 
sulphur, and water; and the amount of pressure in the formations 
penetrated. The lessee shall take formation samples or cores to 
determine

[[Page 292]]

the identity, fluid content, and characteristics of any penetrated 
formation in accordance with requirements approved or prescribed by the 
District Supervisor.
    (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 directional wells at intervals not exceeding 500 feet 
during the normal course of drilling and at intervals not exceeding 100 
feet in all portions of the hole when angle-changes are planned.
    (3) On both vertical and directionally drilled wells, directional 
surveys giving both inclination and azimuth shall be obtained at 
intervals not exceeding 500 feet prior to or upon setting surface or 
intermediate casing, liners, and at total depth. Composite directional 
surveys shall be prepared with the interval shown from the bottom of the 
conductor casing or, in the absence of conductor casing, from the bottom 
of the drive or structural casing to total depth. 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 (MWD) directional 
survey including a listing of the directionally computed inclinations 
and azimuths on a well classified as vertical will be acceptable as 
fulfilling the applicable requirements of this paragraph. In the event a 
composite MWD survey is run, a multishot survey shall be obtained at 
each casing point in order to confirm the MWD results.
    (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) The Regional Supervisor at the request of a holder of an 
adjoining lease may, for the protection of correlative rights, furnish a 
copy of the directional survey for a well drilled within 500 feet of the 
adjacent lease 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 which have their jacking 
equipment removed or have been otherwise immobilized are classified as 
fixed drilling platforms.
    (g) Equipment movement. The movement of drilling rigs and related 
equipment on and off an offshore platform or from well to well on the 
same offshore 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 such rigs and related equipment, unless 
otherwise approved by the District Supervisor. 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.
    (h) Emergency shutdown system. When drilling 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.

[53 FR 10690, Apr. 1, 1988; 53 FR 12227, Apr. 13, 1988, as amended at 54 
FR 50616, Dec. 8, 1989; 55 FR 47752, Nov. 15, 1990; 58 FR 49928, Sept. 
24, 1993. Redesignated and amended at 63 FR 29479, 29485, May 29, 1998]



Secs. 250.402-250.403  [Reserved]



Sec. 250.404  Well casing and cementing.

    (a) General requirements. (1) For the purpose of this subpart, the 
casing strings in order of normal installation are as follows:
    (i) Drive or structural,

[[Page 293]]

    (ii) Conductor,
    (iii) Surface,
    (iv) Intermediate, and
    (v) Production casing.
    (2) The lessee shall case and cement all wells with a sufficient 
number of strings of casing and quantity and quality of cement in a 
manner necessary to prevent release of fluids from any stratum through 
the wellbore (directly or indirectly) into offshore waters, prevent 
communication between separate hydrocarbon-bearing strata, 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 500 pounds per 
square inch (psi). Cement placed across permafrost zones shall be 
designed to set before freezing and have a low heat of hydration.
    (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 casing program design shall be of 
sufficient magnitude to provide well control during drilling and to 
assure safe operations for the life of the well. Any portion of an 
annulus opposite a permafrost zone which is not protected by cement 
shall be filled with a liquid which has a freezing point below the 
minimum permafrost temperature to prevent internal freezeback and which 
is treated to minimize corrosion.
    (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 Supervisor determines that 
subsurface protection against damage to freshwater aquifers and 
permafrost zones 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, running a cement bond log, running a 
temperature survey, or a combination thereof before continuing 
operations. If the evaluation indicates inadequate cementing, the lessee 
shall re-cement or take other remedial actions as approved by the 
District Supervisor.
    (6) A pressure-integrity test shall be run below the surface casing, 
the intermediate casing(s), and liner(s) used as intermediate casing(s). 
The District Supervisor may require a pressure-integrity test to be run 
at the conductor casing shoe due to local geologic conditions or planned 
casing setting depths. Pressure-integrity tests shall be made after 
drilling new hole below the casing shoe and before drilling more than 50 
feet of new hole below a respective casing string. These tests shall be 
conducted either by testing to formation leak-off or by testing to a 
predetermined equivalent mud weight as specified in the approved APD. A 
safe margin, as approved by the District Supervisor, shall be maintained 
between the mud weight in use and the equivalent mud weight at the 
casing shoe as determined in the pressure-integrity test. Drilling 
operations shall be suspended when the safe margin is not maintained. 
Pressure-integrity and pore-pressure test results and related hole-
behavior observations, such as gas-cut mud and well kicks made during 
the course of drilling, shall be used in adjusting the drilling mud 
program and the approved setting depth of the next casing string. The 
results of all tests and of hole-behavior observations made during the 
course of drilling related to formation integrity and pore pressure 
shall be recorded in the driller's report.
    (b) Drive or structural casing. This casing shall be set by driving, 
jetting, or drilling to a minimum depth as may be prescribed or approved 
by the District Supervisor, 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

[[Page 294]]

annular space back to the mud line shall be used.
    (c) Conductor and surface casing requirements. (1) Conductor and 
surface casing setting depths. Conductor and surface 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 approved casing setting depths may be 
adjusted when the change is approved by the District Supervisor to 
permit the casing shoe to be set in a competent formation or below 
formations which should 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 the presence of oil or gas is unknown, upon encountering a 
formation containing oil or gas. Upon encountering unexpected formation 
pressures, the lessee shall submit a revised casing program to the 
District Supervisor for approval. The District Supervisor may permit a 
lessee to drill a well without setting conductor casing provided the 
information from approved logging and mud-monitoring programs for wells 
previously drilled in the immediate vacinity combined with other 
available geologic data are sufficient to demonstrate the absence of 
shallow hydrocarbons or hazards.
    (2) Conductor casing cementing requirements. Conductor casing shall 
be cemented with a quantity of cement that fills the calculated annular 
space back to the mud line except as applicable to the bottom of an 
excavation (glory hole) or to the surface of an artificial island. 
Cement fill in annular spaces 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) Surface casing cementing requirements. (i) Surface 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, surface 
casing shall be cemented with a quantity of cement that fills the 
calculated annular space to the mud line, or as approved or prescribed 
by the District Supervisor.
    (ii) For floating drilling operations, a lesser volume of cement may 
be used to prevent sealing the annular space between the conductor 
casing and surface casing if the District Supervisor determines that the 
uncemented space is necessary to provide protection from burst and 
collapse pressures which may be applied inadvertently to the annulus 
between casings during blowout preventer (BOP) testing operations. Any 
annular space open to the drilled hole shall be sealed in accordance 
with the requirements for abandonment in subpart G, Abandonment of 
Wells, of this part.
    (d) Intermediate casing requirements. (1) Intermediate casing 
string(s) shall be set for protection when geologic characteristics or 
wellbore conditions, as anticipated or as encountered, so indicate.
    (2) Quantities of cement that cover and isolate all hydrocarbon-
bearing zones in the well and isolate abnormal pressure intervals from 
normal pressure intervals shall be used. This requirement for isolation 
may be satisfied by squeeze cementing prior to completion, suspension of 
operations, or abandonment, whichever occurs first. Sufficient cement 
shall be used to provide annular fill-up to a minimum of 500 feet above 
the zones to be isolated or 500 feet above the casing shoe in wells 
where zonal coverage is not required.
    (3) If a liner is to be used as an intermediate string below a 
surface casing string, it shall be lapped a minimum of 100 feet into the 
previous casing string and cemented as required for intermediate casing. 
When a liner is to be used as production casing below a surface casing 
string, it shall be extended to the surface and cemented to avoid 
surface casing being used as production casing.
    (e) Production casing requirements. (1) Production casing shall be 
cemented to cover or isolate all zones above the shoe which contain 
hydrocarbons; but in any case, a volume sufficient to fill the annular 
space at least 500 feet

[[Page 295]]

above the uppermost hydrocarbon-bearing zone shall be used.
    (2) When a liner is to be used as production casing below 
intermediate casing, it shall be lapped a minimum of 100 feet into the 
previous casing string and cemented as required for the production 
casing.



Sec. 250.405  Pressure testing of casing.

    (a) Prior to drilling the plug after cementing and in the cases of 
plugs in production casing strings and liners not planned to be 
subsequently drilled out, all casings, except the drive or structural 
casing, shall be pressure tested to 70 percent of the minimum internal-
yield pressure of the casing or as otherwise approved or required by the 
District Supervisor. 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 
pressure tested again. Additional remedial actions shall be taken until 
a satisfactory pressure test is obtained. The results of all casing 
pressure tests shall be recorded in the driller's report.
    (b) Each production liner lap shall be tested to a minimum of 500 
psi above formation fracture pressure at the shoe of the casing into 
which the liner is lapped, or as otherwise approved or required by the 
District Supervisor. The drilling liner-lap test pressure shall be equal 
to or exceed the pressure that will be encountered at the liner lap when 
conducting the planned pressure-integrity test below the liner shoe. The 
test results shall be recorded on the driller's report. If the test 
indicates an improper seal, remedial action shall be taken which 
provides a proper seal as demonstrated by a satisfactory pressure test.
    (c) In the event of prolonged drill-pipe rotation within a casing 
string run to the surface or extended operations such as milling, 
fishing, jarring, washing over, and other operations which could damage 
the casing, the casing shall be pressure tested or evaluated by a 
logging technique such as a caliper log every 30 days. The evaluation 
results shall be submitted to the District Supervisor with a 
determination of effects of operations on the integrity of the casing 
for continued service during drilling operations and over the producing 
life of the well. If the integrity of the casing in the well has 
deteriorated to an unsafe level, remedial operations shall be conducted 
or additional casing set in accordance with a plan approved by the 
District Supervisor prior to continuing drilling operations.
    (d) After cementing any string of casing other than the structural 
casing string, drilling shall not be resumed until there has been a time 
lapse of 8 hours under pressure for the conductor casing string and 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.



Sec. 250.406  Blowout preventer systems and system components.

    (a) General. The 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)(1), (f), and (g) of this section. The pipe rams shall be of a proper 
size(s) to fit the drill pipe in use.
    (c) Working pressure. The working-pressure rating of any BOP 
component shall exceed the anticipated surface pressure to which it may 
be subjected. The District Supervisor may approve a lower working 
pressure rating for the annular preventer if the lessee demonstrates 
that the anticipated or actual well conditions will not place demands 
above its rated working pressure. (Refer to related requirements in 
Sec. 250.414(f)(3)(ii) of this part.)
    (d) BOP equipment. All BOP systems shall be equipped and provided 
with the following:
    (1) An accumulator system which shall provide sufficient capacity to 
supply 1.5 times the volume of fluid 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

[[Page 296]]

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 backup to the primary accumulator-charging system which shall 
be automatic, supplied by a power source independent from the power 
source to the primary accumulator-charging system, and possess 
sufficient capability to close all BOP components and hold them 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) For surface BOP systems, a choke and a kill line each equipped 
with two full-opening valves. 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 may be 
installed on the kill line in lieu of the remotely controlled valve 
provided two readily accessible manual valves are in place and the check 
valve is placed between the manual valves and the pump. For subsea BOP 
systems, a choke and a kill line each equipped with two full-opening 
valves. At least one of the valves on the choke line and at least one of 
the valves on the kill line shall be remotely controlled.
    (6) A fill-up line above the uppermost preventer.
    (7) A choke manifold suitable for the 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 Supervisor;
    (ii) All components of the choke manifold system shall be protected 
from the danger, if any, of 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 pressure ratings at least as 
great as the rated working pressure of the ram-type BOP's or as 
otherwise approved by the District Supervisor.
    (9) A wellhead assembly with a rated working pressure that exceeds 
the anticipated surface pressure to which it may be subjected.
    (10) The following system components:
    (i) On a conventional drilling rig, a kelly cock installed below the 
swivel (upper kelly cock), essentially full-opening, and a similar valve 
of such design that it can be run through the BOP stack (strippable) 
installed at the bottom of the kelly (lower kelly cock). With a mud 
motor in service and while using drill pipe in lieu of a kelly, one 
kelly cock located above and one strippable kelly cock located below the 
joint of drill pipe employed in lieu of a kelly. On a top-drive system 
equipped with a remote controlled valve, a second and lower strippable 
valve of a conventional kelly cock or comparable type either manually or 
remotely controlled. All required manual and remotely controlled valves 
of a kelly cock or comparable type in a top-drive system must be 
essentially full-opening and tested according to the test pressure and 
test frequency as stated in Sec. 250.407 of this part. A wrench to fit 
each manually operable valve in a conventional drilling rig, mud motor, 
and top-drive system 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

[[Page 297]]

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.
    (11) Locking devices installed on the ram-type preventers.
    (e) Subsea BOP requirements. (1) Prior to drilling below surface and 
intermediate casing, a BOP system shall be installed consisting of at 
least four remote controlled, hydraulically operated BOP's including at 
least two equipped with pipe rams, one with blind-shear rams, and one 
annular type. A subsea accumulator closing unit or a suitable alternate 
approved by the District Supervisor is required 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. When proposed casing 
setting depths or local geology indicate the need for a BOP to provide 
safety during the drilling of the surface hole, the District Supervisor 
may require that a subsea BOP system be installed prior to drilling 
below the conductor casing.
    (2) The BOP system shall include operable dual-pod control systems 
necessary to ensure proper and independent operation of the BOP system 
functions when drilling below the surface casing.
    (3) Prior to the removal of the marine riser, the riser shall be 
displaced with seawater. Sufficient hydrostatic pressure or other 
suitable precautions, such as mechanical or cement plugs or closing the 
BOP, shall be maintained within the wellbore to compensate for the 
reduction in pressure and to maintain a safe controlled well condition.
    (4) Any necessary repair or replacement of the BOP system or a 
system component after installation shall be accomplished under safe 
controlled conditions, (e.g., after casing has been cemented but prior 
to drilling out the casing shoe or by setting a cement plug, bridge 
plug, or a packer).
    (5) When a subsea BOP system is to be used in an area which is 
subject to ice scour, the BOP stack shall be placed in an excavation 
(glory hole) of sufficient depth to assure that the top of the stack is 
below the deepest probable ice-scour depth.
    (f) Surface BOP requirements. Prior to drilling below surface or 
intermediate casing, a BOP system shall be installed consisting of at 
least four remote controlled, hydraulically operated BOP's including at 
least two equipped with pipe rams, one with blind rams, and one annular 
type.
    (g) Tapered drill-string operations. (1) Prior to commencing tapered 
drill-pipe operations, the BOP stack shall be equipped with conventional 
and/or variable-bore pipe rams installed in two or more ram cavities to 
provide the following:
    (i) Two sets of pipe rams capable of sealing around the larger size 
drill string, and
    (ii) One set of pipe rams capable of sealing around the smaller size 
drill string.
    (2) Subsea BOP systems shall have blind-shear ram capability. 
Surface BOP systems shall have blind ram capability.

[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 
29485, May 29, 1998; 63 FR 29607, June 1, 1998]



Sec. 250.407  Blowout preventer (BOP) system tests, inspections, and maintenance.

    (a) BOP pressure testing timeframes. You must pressure test your BOP 
system:
    (1) When installed;
    (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 Supervisor may require testing every 7 days if conditions or 
BOP performance warrant; and
    (3) Before drilling out each string of casing or a liner. The 
District Supervisor may allow you to omit this test if you did not 
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

[[Page 298]]

APD which casing strings and liners meet these criteria.
    (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. 
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 or the pressure otherwise approved by the District Supervisor; 
and
    (3) For annular-type BOP's, the high pressure test must equal 70 
percent of the rated working pressure of the equipment or the pressure 
otherwise approved by the District Supervisor.
    (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 a 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 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 drilling 
operations until that station or pod is operable;
    (4) Pressure test the blind or blind-shear ram during a stump test 
and at all casing points. Additionally, the interval between any blind 
or blind-shear ram tests may not exceed 30 days;
    (5) Function test annulars and rams every 7 days between pressure 
tests;
    (6) Pressure-test variable bore-pipe rams against all sizes of pipe 
in use, excluding drill collars and bottom-hole tools;
    (7) Test affected BOP components following the disconnection or 
repair of any well-pressure containment seal in the wellhead or BOP 
stack assembly;
    (8) Actuate safety valves assembled with proper casing connections 
prior to running casing, and
    (9) If you install casing rams, you must test the ram bonnet before 
running casing.
    (e) Postponing BOP tests. You may postpone a BOP test if you have 
well-control problems such as lost circulation, formation fluid influx, 
or stuck drill pipe. If this occurs, you must conduct the required BOP 
test on the first trip out of the hole. You must record the reason for 
postponing any test in the driller's report.
    (f) Visual inspections. You must visually inspect your surface and 
subsea BOP systems and marine riser at least once each day if weather 
and sea conditions permit. You may use television cameras to inspect 
subsea equipment. The District Supervisor may approve alternate methods 
and frequencies to inspect a marine riser. Casing risers on fixed 
structures and jackup rigs are not subject to the daily underwater 
inspections.
    (g) BOP maintenance. You must maintain your BOP system to ensure 
that the equipment functions properly.
    (h) BOP test records. 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:
    (1) Record BOP test pressures on pressure charts;
    (2) Have your onsite representative certify (sign and date) BOP test 
charts and reports as correct;

[[Page 299]]

    (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 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 drilling; and
    (7) After drilling is completed, you must retain all the records 
listed in paragraph (h)(6) of this section for a period of 2 years at 
the facility, at the lessee's field office nearest the Outer Continental 
Shelf (OCS) facility, or at another location conveniently available to 
the District Supervisor.
    (i) Alternate methods. The District Supervisor 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]



Sec. 250.408  Well-control drills.

    (a) Well-control drills shall be conducted for each drilling crew in 
accordance with the following requirements:
    (1) Drills shall be designed to acquaint each crew member with each 
member's function at the particular test station so each member can 
perform their functions promptly and efficiently.
    (2) A well-control drill plan, applicable to the particular site, 
shall be prepared for each crew member outlining the assignments each 
member is to fulfill during the drill and establishing a prescribed time 
for the completion of each portion of the drill. A copy of the complete 
well-control drill plan shall be posted on the rig floor and/or bulletin 
board.
    (3) The drill shall be carried out during periods of activity 
selected to minimize the risk of sticking the drill pipe or otherwise 
endangering the operation. In each of these drills, the reaction time of 
participants shall be measured up to the point when the designated 
person is prepared to activate the closing sequence of the BOP system. 
The total time for the crew to complete its entire drill assignment 
shall also be measured. This operation shall be recorded on the 
driller's report as ``Well-Control Drill.'' All drills shall be 
initiated by the toolpusher through the raising of the float on the pit-
level device, activating the mud-return indicator, or its equivalent. 
This operation shall be performed at least once each week (well 
conditions permitting) with each crew. The drills shall be timed so they 
will cover a range of different operations which include on-bottom 
drilling and tripping. A diverter drill shall be developed and conducted 
in a similar manner for shallow operations.
    (4) On-bottom drilling. A drill conducted while on bottom shall 
include the following as practicable:
    (i) Detect kick and sound alarm;
    (ii) Position kelly and tool joints so connections are accessible 
from floor, but tool joints are clear of sealing elements in BOP 
systems, stop pumps, check for flow, close in the well;
    (iii) Record time;
    (iv) Record drill-pipe pressure and casing pressure;
    (v) Measure pit gain and mark new level;
    (vi) Estimate volume of additional mud in pits;
    (vii) Weight sample of mud from suction pit;
    (viii) Check all valves on choke manifold and BOP system for correct 
position (open or closed);
    (ix) Check BOP system components and choke manifold for leaks;
    (x) Check flow line and choke exhaust lines for flow;
    (xi) Check accumulator pressure;
    (xii) Prepare to extinguish sources of ignition;
    (xiii) Alert standby boat or prepare safety capsule for launching;
    (xiv) Place crane operator on duty for possible personnel 
evacuation;
    (xv) Prepare to lower escape ladders and prepare other abandonment 
devices for possible use;
    (xvi) Determine materials needed to circulate out kick; and
    (xvii) Time drill and enter drill report on driller's report.

[[Page 300]]

    (5) Tripping pipe. A drill conducted during a trip shall include the 
following as practicable:
    (i) Detect kick and sound alarm;
    (ii) Install safety valve, close safety valve;
    (iii) Position pipe, prepare to close annular preventer;
    (iv) Install inside preventer, open safety valve;
    (v) Record time;
    (vi) Record casing pressure;
    (vii) Check all valves on choke manifold and BOP system for correct 
position (open or closed);
    (viii) Check for leaks on BOP system component and choke manifold;
    (ix) Check flow line and choke exhaust lines for flow;
    (x) Check accumulator pressure;
    (xi) Prepare to extinguish sources of ignition;
    (xii) Alert standby boat or prepare safety capsule for launching;
    (xiii) Place crane operator on duty for possible personnel 
evacuation;
    (xiv) Prepare to lower escape ladders and prepare other abandonment 
devices for possible use;
    (xv) Prepare to strip back to bottom; and
    (xvi) Time drill and enter drill report on driller's report.
    (b) A well-control drill may be required by a Minerals Management 
Service (MMS) authorized representative after consulting with the 
lessee's senior representative present.



Sec. 250.409  Diverter systems.

    (a) When drilling a conductor or surface hole, all drilling units 
shall be equipped with a diverter system consisting of a diverter 
sealing element, diverter lines, and control systems unless otherwise 
approved by the District Supervisor for floating drilling operations. 
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) No later than May 31, 1990, diverter systems shall be in 
compliance with the requirements of this section. The requirements 
applicable to diverters which were in effect April 1, 1988 shall remain 
in effect until May 31, 1990.
    (c) The diverter system shall be equipped with remote-controlled 
valves in the flow and vent 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 valve shall be installed in any part of the 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. All right-angle and sharp turns shall be 
targeted. Flexible hose may be used for diverter 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 vibration. All diverter control instruments 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 provided 
that each outlet has a minimum internal diameter of 8 inches and that 
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) For drilling operations conducted where a floating or 
semisubmersible type of drilling vessel is used and drilling fluids are 
circulated to the drilling vessel, the following shall apply:
    (1) If the diverter system utilizes only one spool outlet, branch 
lines shall be installed to provide downwind diversion capability;
    (2) No spool outlet or diverter line internal diameter shall be less 
than 12 inches; and
    (3) Dynamically positioned drill ships may be equipped with a single 
vent line provided appropriate vessel heading is maintained to allow for 
downwind diversion.

[[Page 301]]

    (f) The diverter sealing element and diverter valves shall be 
pressure tested to a minimum of 200 psi when nippled up on conductor 
casing with a surface wellhead configuration. No more than 7 days shall 
elapse between subsequent similar pressure tests. For surface and subsea 
wellhead configurations, the diverter sealing element, diverter valves, 
and diverter-control systems, including the remote control system, shall 
be actuation-tested and the vent lines flow tested when first installed. 
Subsequent actuation tests shall be conducted not less than once every 
24-hour period thereafter alternating between control stations. All 
pressure test, flow test, and actuation results shall be recorded in the 
driller's report.
    (g) Diverter systems and components for use in subfreezing 
conditions shall be suitable for use under these conditions.



Sec. 250.410  Mud program.

    (a) General requirements. 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) Mud control. (1) Before starting out of the hole with drill 
pipe, the mud shall be properly conditioned by circulation with the 
drill pipe just off bottom to the extent that a volume of drilling mud 
equal to the annular volume is displaced. This procedure may be omitted 
if proper documentation in the driller's report shows the following:
    (i) There is no indication of influx of formation fluids prior to 
starting to pull the drill pipe from the hole.
    (ii) The weight of the returning mud is essentially the same as the 
weight of the mud entering the hole. In the event that the returning mud 
is lighter than the entering mud by a weight differential equal to or 
greater than 0.2 pounds per gallon (1.5 pounds per cubic foot), the mud 
shall be circulated until a volume of drilling mud equal to the annular 
volume is displaced, and the mud properties measured to assure that 
there has been no influx of gas or liquid.
    (iii) Other mud properties recorded on the daily drilling log are 
within the limits established by the approved mud program.
    (2) When mud in the hole is circulated, the driller's report shall 
be so noted.
    (3) When coming out of the hole with drill pipe, the annulus shall 
be filled with mud before the change in mud level decreases the 
hydrostatic pressure by 75 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 mud volume shall be calculated and 
posted near the driller's station. A mechanical, volumetric, or 
electronic device for measuring the amount of mud required to fill the 
hole shall be utilized.
    (4) Drill pipe and downhole tool running and pulling speeds shall be 
at controlled rates so as not to induce an influx of formation fluids 
from the effects of swabbing nor cause a loss of drilling fluid and 
corresponding hydrostatic pressure decrease from the effects of surging.
    (5) When there is an indication of swabbing or influx of formation 
fluids, the safety devices and measures necessary to control the well 
shall be employed. The mud shall be circulated and conditioned, on or 
near bottom, unless well or mud conditions prevent running the drill 
pipe back to the bottom.
    (6) For each casing string, the maximum pressure to be contained 
under the BOP shall be posted near the driller's station.
    (7) In areas where permafrost and/or hydrate zones may be present or 
are known to be present, drilling fluid temperatures shall be controlled 
or other measures taken to drill safely through those zones.
    (8) An operable mud-gas separator and operable degasser shall be 
installed in the mud system prior to commencement of drilling operations 
and shall be maintained for use throughout the drilling of the well.
    (9) The mud in the hole shall be circulated or reverse-circulated 
prior to pulling the drill-stem test tools from the hole. If circulating 
out test fluid is not feasible, test fluids may be bullheaded out of the 
drill-stem test string

[[Page 302]]

and tools with an appropriate kill fluid prior to pulling the test 
tools.
    (c) Mud-testing and monitoring equipment. (1) Mud-testing equipment 
shall be maintained on the drilling rig at all times, and mud tests 
shall be performed once each tour, or more frequently, as conditions 
warrant. Such tests shall be conducted in accordance with industry-
accepted practices and shall include mud density, viscosity, and gel 
strength, hydrogen-ion concentration (pH), filtration, and other tests 
as may be deemed necessary by the District Supervisor in the interests 
of monitoring and maintaining mud quality for safe operations, 
prevention of downhole equipment problems, and for kick detection. The 
results of these tests shall be recorded in the driller's report.
    (2) The following mud-system monitoring equipment shall be installed 
with derrick floor indicators and used when mud returns are established 
and throughout subsequent drilling operations:
    (i) 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.
    (ii) Mud-volume measuring device to accurately determine mud volumes 
required to fill the hole on trips.
    (iii) Mud-return indicator devices which indicate the relationship 
between mud-return flow rate and pump discharge rate. This indicator 
shall include both a visual and an audible warning device.
    (iv) Gas-detecting equipment to monitor the drilling mud returns 
with indicators located in the mud-logging compartment or on the rig 
floor. If the indicators are only in the mud-logging compartment, there 
shall be a means of immediate communication with the rig floor, and the 
gas-detecting equipment shall be continually manned. If the indicators 
are on the rig floor only, an audible alarm shall be installed.
    (d) Mud quantities. (1) Quantities of mud and mud materials at the 
drill site shall be utilized, maintained, and replenished as necessary 
to ensure well control. Those quantities shall be based on known or 
anticipated drilling conditions to be encountered, rig storage capacity, 
weather conditions, and estimated time for delivery.
    (2) Daily inventories of mud and mud materials including weight 
materials and additives at the drill site shall be recorded and those 
records maintained at the well site.
    (3) Drilling operations shall be suspended in the absence of 
sufficient quantities of mud and mud materials to maintain well control.
    (e) Safety precautions in mud-handling areas. Mud-handling areas 
which are classified as per API RP 500 or API RP 505 where dangerous 
concentrations of combustible gas may accumulate shall be equipped with 
ventilation systems and gas monitors as described below no later than 
May 31, 1989. Regulatory requirements in effect on April 1, 1988 are 
applicable until May 31, 1989.
    (1) Be ventilated with high-capacity mechanical ventilation systems 
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, unless such ventilation is provided by natural means. If not 
continuously activated, mechanical ventilation systems shall be 
activated on signal from gas detectors that are operational at all times 
indicating the presence of 1 percent or more of gas by volume.
    (2) Be maintained at a negative pressure relative to an adjacent 
area if mechanical ventilation is installed to meet the requirements in 
paragraph (e)(1) of this section and discharges may be hazardous. The 
negative pressure areas shall be protected with at least one of the 
following: (i) A pressure-sensitive alarm, (ii) open-door alarms on each 
access to the area, (iii) automatic door-closing devices, (iv) air 
locks, or (v) other devices as approved by the District Supervisor.
    (3) Be fitted with gas detectors and alarms except in open areas 
where adequate ventilation is provided by natural means.
    (4) Be equipped with either explosion-proof or pressurized 
electrical equipment to prevent the ignition of explosive gases. Where 
air is used for pressuring, the air intake shall be located outside of, 
and as far as practicable from, hazardous areas.

[[Page 303]]

    (5) Mechanical ventilation systems shall be fitted with alarms which 
are activated upon a failure of the system.
    (6) Gas detection systems shall be tested for operation and 
recalibrated at a frequency such that no more than 90 days shall elapse 
between tests.

[53 FR 10690, Apr. 1, 1988, as amended at 55 FR 47752, Nov. 15, 1990. 
Redesignated at 63 FR 29479, May 29, 1998, as amended at 65 FR 40052, 
June 29, 2000]



Sec. 250.411  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 which force evacuation of the 
drilling crew, prevent station keeping, or require repairs to major 
drilling or well-control equipment. In floating drilling operations, the 
use of blind-shear rams or pipe rams and an inside BOP may be approved 
by the District Supervisor in lieu of the above requirements if 
supported by evidence of special circumstances and/or the lack of 
sufficient time.



Sec. 250.412  Field drilling rules.

    When geological and engineering information available in a field 
enables a District Supervisor to determine specific operating 
requirements appropriate to wells to be drilled in the field, field 
drilling rules may be established on the initiative of the District 
Supervisor, or in response to a request from a lessee. Such rules may 
modify the requirements of this subpart. After field drilling rules have 
been established, development wells to which such rules apply shall be 
drilled in accordance with such rules and other requirements of this 
subpart. Field drilling rules may be amended or cancelled for cause at 
any time upon the initiative of the District Supervisor or upon the 
approval of a request by a lessee.



Sec. 250.413  Supervision, surveillance, and training.

    (a) The lessee shall provide onsite supervision of drilling 
operations on a 24-hour per day basis.
    (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 must be trained and 
qualified according to Subpart O of this part. Records of specific 
training which 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.

[53 FR 10690, Apr. 1, 1988. Redesignated at 63 FR 29479, May 29, 1998; 
64 FR 9065, Feb. 24, 1999]



Sec. 250.414  Applications for permit to drill.

    (a) Prior to commencing the drilling of a well under an approved 
Exploration Plan, Development and Production Plan, or Development 
Operations Coordination Document, the lessee shall file a Form MMS-123, 
APD, with the District Supervisor for approval. Prior to commencing 
operations, written approval from the District Supervisor must be 
received by the lessee unless oral approval has been given pursuant to 
Sec. 250.140.
    (b) The APD's for wells to be drilled from mobile drilling units 
shall include the following:
    (1) An identification of the maximum environmental and operational 
conditions the rig is designed to withstand.
    (2) Applicable current documentation of operational limitations 
imposed by the American Bureau of Shipping classification or other 
appropriate classification society and either a U.S. Coast Guard 
Certificate of Inspection or a U.S. Coast Guard Letter of Compliance.
    (3) For frontier areas, the design and operating limitations beyond 
which suspension, curtailment, or modification of drilling or rig 
operations are required (e.g., vessel motion, offset, riser angle, 
anchor tensions, wind speed, wave height, currents, icing or ice-
loading, settling, tilt or lateral movement, resupply capability) and 
the contingency plans which identify actions to be taken prior to 
exceeding the design or operating limitations of the rig.
    (4) A program which provides for safety in drilling operations where 
a floating or semisubmersible type of

[[Page 304]]

drilling vessel is used and formation competency at the structural and/
or conductor casing setting depth(s) is (are) not adequate to permit 
circulation of drilling fluids to the vessel while drilling the 
conductor and/or surface hole. This program shall include all known 
pertinent information including seismic and geologic data, water depth, 
drilling-fluid hydrostatic pressure, a schematic diagram indicating the 
equipment to be installed from the rotary table to the proposed 
conductor and/or surface casing seat(s), and the contingency plan for 
moving off location.
    (c) The APD's shall include rated capacities of the proposed 
drilling unit and of major drilling equipment.
    (d) In those areas which are subject to subfreezing conditions, the 
lessee shall furnish evidence that the drilling equipment, BOP system 
and components, drilling safety systems, diverter systems, and other 
associated equipment and materials are suitable for drilling operations 
under subfreezing conditions.
    (e) After a drilling unit has been approved for use in an MMS 
District, the information listed in paragraphs (b) (1), (2), and (3), 
(c), and (d) of this section need not be resubmitted unless required by 
the District Supervisor or there are changes in equipment that affect 
the rated capacity of the unit.
    (f) An APD shall include the following in addition to a fully 
completed Form MMS-123:
    (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. Locations shall be indicated in feet from the block line.
    (2) The design criteria considered for the well and for well 
control, including the following:
    (i) Pore pressures.
    (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 which can reasonably be expected to 
be exerted upon a casing string and its related wellhead equipment). In 
the calculation of an 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, 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 pressures the calculations 
used to determine these pressures during the drilling phase and the 
completion phase, including the anticipated surface pressure used for 
production string design.
    (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.
    (viii) Permafrost zones, if applicable.
    (3) A BOP equipment program including the following:
    (i) The pressure rating of BOP equipment.
    (ii) A well-control procedure for use of the annular preventer for 
those wells where the anticipated surface pressure exceeds the rated 
working pressure of the annular preventer.
    (iii) A description of subsea BOP accumulator system or other type 
of closing system proposed for use.
    (iv) 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 
lessee or contractor personnel.
    (v) 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

[[Page 305]]

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;
    (ii) Casing design safety factors for tension, collapse, and burst 
with the assumptions made to arrive at these values; and
    (iii) In areas containing permafrost, casing programs that 
incorporate setting depths for conductor and surface casing based on the 
anticipated depth of the permafrost at the proposed well location and 
which utilize the current state-of-the-art methods to safely drill and 
set casing. The casing program shall provide protection from thaw 
subsidence and freezeback effect, proper anchorage, and well control.
    (5) The drilling prognosis including the following:
    (i) Projected plans for coring at specified depths;
    (ii) Projected plans for logging;
    (iii) Estimated depths to the top of significant marker formations; 
and
    (iv) Estimated depths at which encounters with significant porous 
and permeable zones containing fresh water, 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) A plot of the estimated pore pressures and formation fracture 
gradients and the proposed mud weights and casing setting depths on the 
same sheet.
    (10) A H2S Contingency Plan, if applicable, and not 
submitted previously.
    (11) Such other information as may be required by the District 
Supervisor.
    (g) Public information copies of the APD shall be submitted in 
accordance with Sec. 250.190 of this part.

[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]



Sec. 250.415  Sundry notices and reports on wells.

    (a) Notices of the lessee's intention to change plans, make changes 
in major drilling equipment, deepen or plug back a well, or engage in 
similar activities and subsequent reports pertaining to such operations 
shall be submitted to the District Supervisor on Form MMS-124, Sundry 
Notices and Reports on Wells. Prior to commencing operations, written 
approval must be received from the District Supervisor unless oral 
approval is obtained.
    (b) The Form MMS-124 submitted shall contain a detailed statement of 
the proposed work that will materially change from the approved work 
described in the APD. Information submitted shall include the present 
status of the well, including the production string or last string of 
casing, the well depth, the present production zones and productive 
capability, and all other information specified on Form MMS-124. 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) A Form MMS-124 with a plat, certified by a registered land 
surveyor, shall be filed as soon as the well's final surveyed surface 
location, water depth, and the rotary kelly bushing elevation have been 
determined.
    (d) Public information copies of Sundry Notices and Reports on Wells 
shall be submitted in accordance with Sec. 250.190 of this part.

[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]



Sec. 250.416  Well records.

    (a) Complete and accurate records for each well and of 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 Supervisor. The records shall 
contain a description of any significant malfunction or problem; all the 
formations penetrated; the content and character of oil, gas, and other 
mineral deposits and water in each formation; the kind, weight, size, 
grade, and setting depth of casing; all well logs and surveys run

[[Page 306]]

in the wellbore; and all other information required by the District 
Supervisor in the interests of resource evaluation, waste prevention, 
conservation of natural resources, protection of correlative rights, 
safety, and environment.
    (b) When drilling operations are suspended, or temporarily 
prohibited under the provisions of Sec. 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 
Supervisor 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, Well Summary Report, or Form MMS-124, as 
appropriate.
    (c) Upon request by the Regional or District 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) Paleontological reports identifying microscopic fossils by depth 
and/or washed samples of drill cuttings normally maintained by the 
lessee for paleontological determinations;
    (3) Copies of the daily driller's report at a frequency as 
determined by the District Supervisor. Items to be reported include spud 
dates, casing setting depths, cement quantities, casing characteristics, 
pressure integrity tests, mud weights, kicks, lost returns, and any 
unusual activities; and
    (4) Legible, exact copies of service company reports on cementing, 
perforating, acidizing, analyses of cores, testing, or other similar 
services.
    (d) As soon as available, the lessee shall transmit copies (field or 
final prints of individual runs) of logs or charts of electrical, 
radioactive, sonic, and other well-logging operations, directional-well 
surveys, and analyses of cores. Composite logs of multiple runs and 
directional-well surveys shall be transmitted to the District Supervisor 
in duplicate as soon as available but not later than 30 days after 
completion of each well.
    (e) If the drilling unit moves from the wellbore prior to completing 
the well, the lessee shall submit to the District Supervisor copies of 
the well records with completed Form MMS-124, within 30 days after 
moving from the wellbore.
    (f) If the Regional or District Supervisor determines that 
circumstances warrant, the lessee shall submit any other reports and 
records of operations, including paleontological interpretations based 
upon identification of microscopic fossils, in the manner and form 
prescribed by the Regional or District Supervisor.
    (g) Records relating to the drilling of a well shall be retained for 
a period of 90 days after drilling operations are completed. Records 
relating to the completion of a well or of any workover activity which 
materially alters the completion configuration or materially affects or 
alters a hydrocarbon-bearing zone shall be kept until the well is 
permanently plugged and abandoned.

[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]



Sec. 250.417  Hydrogen sulfide.

    (a) What precautions must I take when operating in an H2S 
area? You must:
    (1) Take all necessary and feasible precautions and measures to 
protect personnel from the toxic effects of H2S and to 
mitigate damage to property and the environment caused by 
H2S. You must follow the requirements of this section when 
conducting drilling, 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.
    H2S absent means:

[[Page 307]]

    (1) Drilling, logging, coring, testing, or producing operations have 
confirmed the absence of H2S in concentrations that could 
potentially result in atmospheric concentrations of 20 ppm or more of 
H2S; or
    (2) Drilling in the surrounding areas and correlation of geological 
and seismic data with equivalent stratigraphic units have confirmed an 
absence of H2S throughout the area to be drilled.
    H2S present means that drilling, logging, coring, 
testing, or producing operations have confirmed the presence of 
H2S in concentrations and volumes that could potentially 
result in atmospheric concentrations of 20 ppm or more of 
H2S.
    H2S unknown means the designation of a zone or geologic 
formation where neither the presence nor absence of H2S has 
been confirmed.
    Well-control fluid means drilling mud and completion or workover 
fluid as appropriate to the particular operation being conducted.
    (c) Classifying an area for the presence of H2S. You 
must:
    (1) Request and obtain an approved classification for the area from 
the Regional Supervisor before you begin operations. Classifications are 
``H2S absent,'' H2S present,'' or ``H2S 
unknown'';
    (2) Submit your request with your application for permit to drill;
    (3) Support your request with available information such as geologic 
and geophysical data and correlations, well logs, formation tests, cores 
and analysis of formation fluids; and
    (4) Submit a request for reclassification of a zone when additional 
data indicate a different classification is needed.
    (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 H2S Contingency Plan. 
Before you begin operations, you must submit an H2S 
Contingency Plan to the District Supervisor for approval. Do not begin 
operations before the District Supervisor 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;

[[Page 308]]

    (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,

[[Page 309]]

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;
    (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 
H2S safety discussions on the facility? You must:
    (i) Conduct a drill for each person at the facility during normal 
duty hours at least once every 7-day period. The drills must consist of 
a dry-run performance of personnel activities related to assigned jobs.
    (ii) At a safety meeting or other meetings of all personnel, discuss 
drill performance, new H2S considerations at the facility, 
and other updated H2S information at least monthly.
    (2) What documentation do I need? You must keep records of 
attendance for:
    (i) Drilling, well-completion, and well-workover operations at the 
facility until operations are completed; and
    (ii) Production operations at the facility or at the nearest field 
office for 1 year.
    (i) Visual and audible warning systems--(1) How must I install wind 
direction equipment? You must install wind-direction equipment in a 
location visible at all times to individuals on or in the immediate 
vicinity of the facility.
    (2) When do I need to display operational danger signs, display 
flags, or activate visual or audible alarms?
    (i) You must display warning signs at all times on facilities with 
wells capable of producing H2S and on facilities that process 
gas containing H2S in concentrations of 20 ppm or more.
    (ii) In addition to the signs, you must activate audible alarms and 
display flags or activate flashing red lights when atmospheric 
concentration of H2S reaches 20 ppm.
    (3) What are the requirements for signs? Each sign must be a 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

[[Page 310]]

instructions on the initiation of appropriate protective measures.
    (j) H2S-detection and H2S monitoring 
equipment--(1) What are the requirements for an H2S detection 
system? An H2S detection system must:
    (i) Be capable of sensing a minimum of 10 ppm of H2S in 
the atmosphere; and
    (ii) Activate audible and visual alarms when the concentration of 
H2S in the atmosphere reaches 20 ppm.
    (2) Where must I have sensors for drilling, well-completion, and 
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 Supervisor 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 Supervisor may require additional sensors or 
other monitoring capabilities, if warranted by site specific conditions.
    (6) How must I functionally test the H2S Detectors?
    (i) Personnel trained to calibrate the particular H2S 
detector equipment being used must test detectors by exposing them to a 
known concentration in the range of 10 to 30 ppm of H2S.
    (ii) If the results of any functional test are not within 2 ppm or 
10 percent, whichever is greater, of the applied 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.

[[Page 311]]

    (iii) If equipment requires calibration as a result of two 
consecutive functional tests, the District Supervisor 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 
Supervisor 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 Supervisor will 
consider dispersion modeling results from a possible release to 
determine if 20 ppm H2S concentration levels could be 
exceeded at nearby facilities.
    (11) What must I do to protect against SO2 if I burn gas 
containing H2S? You must:
    (i) Monitor the 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 to conform to 
ANSI Z88.2, American National Standard for Respiratory Protection.
    (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 
Supervisor 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,

[[Page 312]]

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 H2S 
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 
facility.
    (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 
Sec. 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

[[Page 313]]

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 H2S. When 
testing a well in a zone with H2S present, you must do all of 
the following:
    (1) Before starting a well test, conduct safety meetings for all 
personnel who will be on the facility during the test. At the meetings, 
emphasize the use of protective-breathing equipment, first-aid 
procedures, and the Contingency Plan. Only competent personnel who are 
trained and are knowledgeable of the hazardous effects of H2S 
must be engaged in these tests.
    (2) Perform well testing with the minimum number of personnel in the 
immediate vicinity of the rig floor and with the appropriate test 
equipment to safely and adequately perform the test. During the test, 
you must continuously monitor H2S levels.
    (3) Not burn produced gases except through a flare which meets the 
requirements of paragraph (q)(6) of this section. Before flaring gas 
containing H2S, you must activate SO2 monitoring 
equipment in accordance with paragraph (j)(11) of this section. If you 
detect SO2 in excess of 2 ppm, you must implement the 
personnel protective measures in your H2S Contingency Plan, 
required by paragraph (f)(13)(iv) of this section. You must also follow 
the requirements of Sec. 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 Supervisor. 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 H2S-bearing fluids that 
conform to NACE Standard MR0175-99.
    (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 H2S zone--
(1) Coring operations. When you conduct coring operations in 
H2S-bearing zones, all personnel in the working area must 
wear protective-breathing equipment at least 10 stands in advance of 
retrieving

[[Page 314]]

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 H2S-
bearing zone. If you decide to circulate out a kick, personnel in the 
working area during bottoms-up and extended-kill operations must wear 
protective-breathing equipment.
    (5) Drill- and workover-string design and precautions. Drill- and 
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 
Supervisor.
    (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 Supervisor an 
analysis of the anticipated H2S content of the water at the 
final treatment vessel and at the discharge point. The District 
Supervisor may require that the water be treated for removal of 
H2S. The District Supervisor 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]

[[Page 315]]



            Subpart E--Oil and Gas Well-Completion Operations



Sec. 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.



Sec. 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.



Sec. 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 Supervisor. 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]



Sec. 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.



Sec. 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 Sec. 250.417 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 Sec. 250.417 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]



Sec. 250.505  Subsea completions.

    No subsea well completion shall be commenced until the lessee 
obtains written approval from the District Supervisor in accordance with 
Sec. 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]



Sec. 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.

[[Page 316]]



Secs. 250.507-250.508  [Reserved]



Sec. 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]



Sec. 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.



Sec. 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.



Sec. 250.512  Field well-completion rules.

    When geological and engineering information available in a field 
enables the District Supervisor to determine specific operating 
requirements, field well-completion rules may be established on the 
District Supervisor'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 Supervisor or upon the request of a lessee.



Sec. 250.513  Approval and reporting of well-completion operations.

    (a) No well-completion operation shall begin until the lessee 
receives written approval from the District Supervisor. If completion is 
planned and the data are available at the time the Application for 
Permit to Drill, Form MMS-123 (see Sec. 250.414 of this part), is 
submitted, approval for a well completion may be requested on that form. 
If the completion has not been approved or if the completion objective 
or plans have significantly changed, approval for such operations shall 
be requested on Form MMS-124, Sundry Notices and Reports on Wells.
    (b) The following information shall be submitted with Form MMS-124 
(or with Form MMS-123):
    (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; and
    (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 Sec. 250.417 of this part.
    (c) Within 30 days after completion, Form MMS-125, Well Summary 
Report, including a schematic of the tubing and subsurface equipment, 
shall be submitted to the District Supervisor.

[[Page 317]]

    (d) Public information copies of Form MMS-125 shall be submitted in 
accordance with Sec. 250.190.

[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]



Sec. 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.



Sec. 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 shall 
include the following:
    (1) Three preventers, when the expected surface pressure is less 
than 5,000 psi, consisting of an annular preventer, one preventer 
equipped with pipe rams, and one preventer equipped with blind or blind-
shear rams.
    (2) Four preventers, when the expected surface pressure is 5,000 psi 
or greater, or for multiple tubing strings consisting of an annular 
preventer, two preventers equipped with pipe rams, and one preventer 
equipped with blind or blind-shear rams. When dual tubing strings are 
being handled simultaneously, dual pipe rams shall be installed on one 
of the pipe-ram preventers.
    (3) When tapered drill string is used, the minimum BOP system shall 
include either of the following:
    (i) Four preventers, when the expected surface pressure is less than 
5,000 psi, consisting of an annular preventer, two sets of pipe rams, 
one capable of sealing around the larger size drill string and one 
capable of sealing around the smaller size drill string (one set of 
variable bore rams may be substituted for the two sets of pipe rams), 
and one preventer equipped with blind or blind shear rams; or
    (ii) Five preventers, when the expected surface pressure is 5,000 
psi or greater, consisting of an annular preventer, two sets of pipe 
rams capable of sealing around the larger size drill string, one set of 
pipe rams capable of sealing around the smaller size drill string (one 
set of variable bore rams may be substituted for one set of pipe

[[Page 318]]

rams capable of sealing around the larger size drill string and the set 
of pipe rams capable of sealing around the smaller size drill string), 
and a preventer equipped with blind or blind-shears rams.
    (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]



Sec. 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 Supervisor 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 Supervisor 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.

[[Page 319]]

    (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 Supervisor 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 Supervisor.
    (j) Alternate methods. The District Supervisor 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]



Sec. 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 Supervisor.
    (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

[[Page 320]]

observed on a well, the lessee shall immediately notify the District 
Supervisor.
    (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 Sec. 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



Sec. 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.



Sec. 250.601  Definitions.

    When used in this subpart, the following terms shall have the 
meanings given below:
    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.



Sec. 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 
Supervisor. 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.



Sec. 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.

[[Page 321]]



Sec. 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 Sec. 250.417 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 Sec. 250.417 
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]



Sec. 250.605  Subsea workovers.

    No subsea well-workover operation including routine operations shall 
be commenced until the lessee obtains written approval from the District 
Supervisor in accordance with Sec. 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]



Sec. 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.



Secs. 250.607-250.608  [Reserved]



Sec. 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.



Sec. 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]



Sec. 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.



Sec. 250.612  Field well-workover rules.

    When geological and engineering information available in a field 
enables the District Supervisor to determine specific operating 
requirements, field well-workover rules may be established on the 
District Supervisor'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-

[[Page 322]]

workover rules may be amended or canceled for cause at any time upon the 
initiative of the District Supervisor or upon the request of a lessee.



Sec. 250.613  Approval and reporting for well-workover operations.

    (a) No well-workover operation except routine ones, as defined in 
Sec. 250.601 of this part, shall begin until the lessee receives written 
approval from the District Supervisor. Approval for such operations 
shall be requested on Form MMS-124, Sundry Notices and Reports on Wells.
    (b) The following information shall be submitted 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; and
    (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 Sec. 250.417 of this part.
    (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, Sundry Notices and Reports on 
Wells, shall be submitted to the District Supervisor, 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, Well 
Summary Report, shall be submitted to the District Supervisor 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]



Sec. 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.

[[Page 323]]



Sec. 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 shall include of the following:
    (1) Three preventers, when the expected surface pressure is less 
than 5,000 psi, consisting of an annular preventer, one preventer 
equipped with pipe rams, and one preventer equipped with blind or blind-
shear rams.
    (2) Four preventers, when the expected surface pressure is 5,000 psi 
or greater, or for multiple tubing strings consisting of an annular 
preventer, two preventers equipped with pipe rams, and one preventer 
equipped with blind or blind-shear rams. When dual tubing strings are 
being handled simultaneously, dual pipe rams shall be installed on one 
of the pipe-ram preventers.
    (3) When a tapered drill string is used, the minimum BOP system 
shall include either of the following:
    (i) Four preventers, when the expected surface pressure is less than 
5,000 psi, consisting of an annular preventer, two sets of pipe rams, 
one capable of sealing around the larger size drill string, and one 
capable of sealing around the smaller size drill string (one set of 
variable bore rams may be substituted for the two sets of pipe rams), 
and one preventer equipped with blind or blind-shear rams; or
    (ii) Five preventers, when the expected surface pressure is 5,000 
psi or greater, consisting of an annular preventer, two sets of pipe 
rams capable of sealing around the larger size drill string, one set of 
pipe rams capable of sealing around the smaller size drill string (one 
set of variable bore rams may be substituted for one set of pipe rams 
capable of sealing around the larger size drill string and the set of 
pipe rams capable of sealing around the smaller size drill string), and 
a preventer equipped with blind or blind-shear rams.
    (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

[[Page 324]]

with the tree in place and performed through the wellhead inside of 
conventional tubing using small-diameter jointed pipe (usually \3/4\ 
inch to 1\1/4\ 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) The minimum BOP-system components for well-workover operations 
with the tree in place and performed by manipulating spooled, nonjointed 
pipe through the wellhead, i.e., coiled-tubing operations, shall include 
the following:
    (1) One set of pipe rams hydraulically operated,
    (2) One two-way slip assembly hydraulically operated,
    (3) One pipe-cutter assembly hydraulically operated,
    (4) One set of blind rams hydraulically operated,
    (5) One pipe-stripper assembly, and
    (6) One spool with side outlets.
    (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]



Sec. 250.616  Blowout preventer system testing, records, and drills.

    (a) Prior to conducting high-pressure tests, all BOP system 
components shall be successfully tested to a low pressure of 200 to 300 
psi. Ram-type BOP's, related control equipment, including the choke and 
kill manifolds, and safety valves shall be successfully tested to the 
rated working pressure of the BOP equipment or as otherwise approved by 
the District Supervisor. Variable bore rams shall be pressure-tested 
against all sizes of drill pipe in the well excluding drill collars. 
Surface BOP systems shall be pressure tested with water. The annular-
type BOP shall be successfullly tested at 70 percent of its rated 
working pressure or as otherwise approved by the District Supervisor. 
Each valve in the choke and kill manifolds shall be successfully, 
sequentially pressure tested to the ram-type BOP test pressure.
    (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) The lessee shall record pressure conditions during BOP tests on 
pressure charts, unless otherwise approved

[[Page 325]]

by the District Supervisor. The test interval 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.
    (e) 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 actity, 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 Supervisor.

[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]



Sec. 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 Supervisor.
    (c) When reinstalling the tree, the wellhead shall be equiped 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 Supervisor.
    (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 Sec. 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]



Sec. 250.618  Wireline operations.

    The lessee shall comply with the following requirements during 
routine, as defined in Sec. 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.

[[Page 326]]

    (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--Abandonment of Wells



Sec. 250.700  General requirements.

    (a) The lessee shall abandon all wells in a manner to assure 
downhole isolation of hydrocarbon zones, protection of freshwater 
aquifers, clearance of sites so as to avoid conflict with other uses of 
the Outer Continental Shelf (OCS), and prevention of migration of 
formation fluids within the wellbore or to the seafloor. Any well which 
is no longer used or useful for lease operations shall be plugged and 
abandoned in accordance with the provisions of this subpart. However, no 
production well shall be abandoned until its lack of capacity for 
further profitable production of oil, gas, or sulphur has been 
demonstrated to the satisfaction of the District Supervisor. No well 
shall be plugged if the plugging operations would jeopardize safe and 
economic operations of nearby wells, unless the well poses a hazard to 
safety or the environment.
    (b) Lessees must plug and abandon all well bores, remove all 
platforms or other facilities, and clear the ocean of all obstructions 
to other users. This obligation:
    (1) Accrues to the lessee when the well is drilled, the platform or 
other facility is installed, or the obstruction is created; and
    (2) Is the joint and several responsibility of all lessees and 
owners of operating rights under the lease at the time the obligation 
accrues, and of each future lessee or owner of operating rights, until 
the obligation is satisfied under the requirements of this part.

[53 FR 10690, Apr. 1, 1988, as amended at 62 FR 27955, May 22, 1997. 
Redesignated at 63 FR 29479, May 29, 1998]



Sec. 250.701  Approvals.

    The lessee shall not commence abandonment operations without prior 
approval of the District Supervisor. The lessee shall submit a request 
on Form MMS-124, Sundry Notices and Reports on Wells, for approval to 
abandon a well and a subsequent report of abandonment within 30 days 
from completion of the work in accordance with the following:
    (a) Notice of Intent to Abandon Well. A request for approval to 
abandon a well shall contain the reason for abandonment including 
supportive well logs and test data, a description and schematic of 
proposed work including depths, type, location, length of plugs, the 
plans for mudding, cementing, shooting, testing, casing removal, and 
other pertinent information.
    (b) Subsequent report of abandonment. The subsequent report of 
abandonment shall include a description of the manner in which the 
abandonment or plugging work was accomplished, including the nature and 
quantities of materials used in the plugging, and all information listed 
in paragraph (a) of this section with a revised schematic. If an attempt 
was made to cut and pull any casing string, the subsequent report shall 
include a description of the methods used, size of casing removed, depth 
of the casing removal point, and the amount of the casing removed from 
the well.

[53 FR 10690, Apr. 1, 1988, as amended at 58 FR 49928, Sept. 24, 1993. 
Redesignated at 63 FR 29479, May 29, 1998]



Sec. 250.702  Permanent abandonment.

    (a) Isolation of zones in open hole. In uncased portions of wells, 
cement plugs shall be set to extend from a minimum of 100 feet below the 
bottom to 100 feet above the top of any oil, gas, or freshwater zones to 
isolate fluids in the strata in which they are found and to prevent them 
from escaping into other strata or to the seafloor. The placement of 
additional cement plugs to prevent the migration of formation fluids in 
the wellbore may be required by the District Supervisor.
    (b) Isolation of open hole. Where there is an open hole below the 
casing, a cement plug shall be placed in the deepest casing by the 
displacement method and shall extend a minimum of 100 feet above and 100 
feet below the casing shoe. In lieu of setting a cement plug

[[Page 327]]

across the casing shoe, the following methods are acceptable:
    (1) A cement retainer and a cement plug shall be set. The cement 
retainer shall have effective back-pressure control and shall be set not 
less than 50 feet and not more than 100 feet above the casing shoe. The 
cement plug shall extend at least 100 feet below the casing shoe and at 
least 50 feet above the retainer.
    (2) If lost circulation conditions have been experienced or are 
anticipated, a permanent-type bridge plug may be placed within the first 
150 feet above the casing shoe with a minimum of 50 feet of cement on 
top of the bridge plug. This bridge plug shall be tested in accordance 
with paragraph (g) of this section.
    (c) Plugging or isolating perforated intervals. A cement plug shall 
be set by the displacement method opposite all perforations which have 
not been squeezed with cement. The cement plug shall extend a minimum of 
100 feet above the perforated interval and either 100 feet below the 
perforated interval or down to a casing plug, whichever is the lesser. 
In lieu of setting a cement plug by the displacement method, the 
following methods are acceptable, provided the perforations are isolated 
from the hole below:
    (1) A cement retainer and a cement plug shall be set. The cement 
retainer shall have effective back-pressure control and shall be set not 
less than 50 feet and not more than 100 feet above the top of the 
perforated interval. The cement plug shall extend at least 100 feet 
below the bottom of the perforated interval with 50 feet placed above 
the retainer.
    (2) A permanent-type bridge plug shall be set within the first 150 
feet above the top of the perforated interval with at least 50 feet of 
cement on top of the bridge plug.
    (3) A cement plug which is at least 200 feet long shall be set by 
the displacement method with the bottom of the plug within the first 100 
feet above the top of the perforated interval.
    (d) Plugging of casing stubs. If casing is cut and recovered leaving 
a stub, the stub shall be plugged in accordance with one of the 
following methods:
    (1) A stub terminating inside a casing string shall be plugged with 
a cement plug extending at least 100 feet above and 100 feet below the 
stub. In lieu of setting a cement plug across the stub, the following 
methods are acceptable:
    (i) A cement retainer or a permanent-type bridge plug shall be set 
not less than 50 feet above the stub and capped with at least 50 feet of 
cement, or
    (ii) A cement plug which is at least 200 feet long shall be set with 
the bottom of the plug within 100 feet above the stub.
    (2) If the stub is below the next larger string, plugging shall be 
accomplished as required to isolate zones or to isolate an open hole as 
described in paragraphs (a) and (b) of this section.
    (e) Plugging of annular space. Any annular space communicating with 
any open hole and extending to the mud line shall be plugged with at 
least 200 feet of cement.
    (f) Surface plug. A cement plug which is at least 150 feet in length 
shall be set with the top of the plug within the first 150 feet below 
the mud line. The plug shall be placed in the smallest string of casing 
which extends to the mud line.
    (g) Testing of plugs. The setting and location of the first plug 
below the surface plug shall be verified by one of the following 
methods:
    (1) The lessee shall place a minimum pipe weight of 15,000 pounds on 
the cement plug, cement retainer, or bridge plug. The cement placed 
above the bridge plug or retainer is not required to be tested.
    (2) The lessee shall test the plug with a minimum pump pressure of 
1,000 pounds per square inch with a result of no more than a 10-percent 
pressure drop during a 15-minute period.
    (h) Fluid left in hole. Each of the respective intervals of the hole 
between the various plugs shall be filled with fluid of sufficient 
density to exert a hydrostatic pressure exceeding the greatest formation 
pressure in the intervals between the plugs at time of abandonment.
    (i) Clearance of location. All wellheads, casings, pilings, and 
other obstructions shall be removed to a depth of at least 15 feet below 
the mud

[[Page 328]]

line or to a depth approved by the District Supervisor. The lessee shall 
verify that the location has been cleared of all obstructions in 
accordance with Sec. 250.704 of this part. The requirement for removing 
subsea wellheads or other obstructions and for verifying location 
clearance may be reduced or eliminated when, in the opinion of the 
District Supervisor, the wellheads or other obstructions would not 
constitute a hazard to other users of the seafloor or other legitimate 
uses of the area.
    (j) Requirements for permafrost areas. The following requirements 
shall be implemented for permafrost areas:
    (1) Fluid left in the hole adjacent to permafrost zones shall have a 
freezing point below the temperature of the permafrost and shall be 
treated to inhibit corrosion.
    (2) The cement used for cement plugs placed across permafrost zones 
shall be designed to set before freezing and to have a low heat of 
hydration.

[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 
29485, May 29, 1998]



Sec. 250.703  Temporary abandonment.

    (a) Any drilling well which is to be temporarily abandoned shall 
meet the requirements for permanent abandonment (except for the 
provisions in Secs. 250.702 (f) and (i), and 250.704) and the following:
    (1) A bridge plug or a cement plug at least 100 feet in length shall 
be set 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.
    (2) A retrievable or a permanent-type bridge plug or a cement plug 
at least 100 feet in length, shall be set in the casing within the first 
200 feet below the mud line.
    (b) Subsea wellheads, casing stubs, or other obstructions above the 
seafloor remaining after temporary abandonment will be protected in such 
a manner as to allow commercial fisheries gear to pass over the 
structure without damage to the structure or fishing gear. Depending on 
water depth, nature and height of obstruction above the seafloor, and 
the types and periods of fishing activity in the area, the District 
Supervisor may waive this requirement.
    (c) In order to maintain the temporarily abandoned status of a well, 
the lessee shall provide, within 1 year of the original temporary 
abandonment and at successive 1-year intervals thereafter, an annual 
report describing plans for reentry to complete or permanently abandon 
the well.
    (d) Identification and reporting of subsea wellheads, casing stubs, 
or other obstructions extending above the mud line will be accomplished 
in accordance with the requirements of the U.S. Coast Guard.

[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 
29485, May 29, 1998]



Sec. 250.704  Site clearance verification.

    (a) The lessees shall verify site clearance after abandonment by one 
or more of the following methods as approved by the District Supervisor:
    (1) Drag a trawl in two directions across the location,
    (2) Perform a diver search around the wellbore,
    (3) Scan across the location with a side-scan or on-bottom scanning 
sonar, or
    (4) Use other methods based on particular site conditions.
    (b) Certification that the area was cleared of all obstructions, the 
date the work was performed, the extent of the area searched around the 
location, and the search method utilized shall be submitted on Form MMS-
124.

[53 FR 10690, Apr. 1, 1988, as amended at 58 FR 49928, Sept. 24, 1993. 
Redesignated at 63 FR 29479, May 29, 1998]



            Subpart H--Oil and Gas Production Safety Systems



Sec. 250.800  General requirements.

    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

[[Page 329]]

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.



Sec. 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 
Supervisor 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 Sec. 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 Supervisor'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 Supervisor.
    (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 shall be inspected, installed, maintained, and tested 
in accordance with American Petroleum Institute Recommended Practice 
14B, Recommended Practice for Design, Installation, and Operation of 
Subsurface Safety Valve Systems.
    (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 Supervisor on a case-by-case basis, 
when

[[Page 330]]

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 Supervisor 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, Sundry Notices and Reports on 
Wells, in Sec. 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 
Sec. 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 
Supervisor.
    (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 Sec. 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]



Sec. 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. All platform production facilities shall be protected 
with a basic and ancillary surface safety system designed, analyzed, 
installed, tested, and maintained in operating condition in accordance 
with the provisions of API RP 14C, Recommended Practice for Analysis, 
Design, Installation and Testing of Basic Surface Safety Systems for 
Offshore Production Platforms. If processing components are to be 
utilized, other than those for which Safety Analysis Checklists are 
included in API RP 14C, the analysis technique and documentation 
specified therein shall be utilized to determine the effects and 
requirements of these components upon the safety system. Safety device 
requirements for pipelines are contained in Sec. 250.1004 of this part.
    (c) Specification for surface safety valves (SSV) and underwater 
safety valves (USV). All wellhead SSV's,

[[Page 331]]

USV's, and their actuators which are installed in the OCS shall conform 
to the requirements in Sec. 250.806 of this part.
    (d) Use of SSV's and USV's. All SSV's and USV's shall be inspected, 
installed, maintained, and tested in accordance with API RP 14H, 
Recommended Practice for Use of Surface Safety Valves and Underwater 
Safety Valves Offshore. 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 Supervisor 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 Supervisor. 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 flow diagram (API RP 14C, Figure E1) and the related 
Safety Analysis Function Evaluation chart (API RP 14C, subsection 4.3c).
    (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.
    (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, 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 Supervisor 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.

[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]



Sec. 250.803  Additional production system requirements.

    (a) General. Lessees shall comply with the following production 
safety system requirements (some of which are in addition to those 
contained in API RP 14C), incorporated by reference in Sec. 250.802(b) 
of this part.
    (b) Design, installation, and operation of additional production 
systems. (1) Pressure and fired vessels. Pressure and fired

[[Page 332]]

vessels shall be designed, fabricated, code stamped, and maintained in 
accordance with applicable provisions of sections I, IV, and VIII of the 
ASME Boiler and Pressure Vessel Code. All existing uncoded vessels in 
use must be justified and approval for continued use obtained from the 
District Supervisor no later than August 29, 1988.
    (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 Supervisor. 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 Supervisor on a 
case-by-case basis.
    (2) Flowlines. (i) Flowlines from wells shall be equipped with high- 
and low-pressure shut-in sensors located in accordance with section A.1 
and Figure A1 of API RP 14C. 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 
Supervisor. 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 Supervisor. 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

[[Page 333]]

the valve(s) to close before exceeding the maximum allowable working 
pressure.
    (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 shall conform to the requirements of Appendix C, 
section C1, of API RP 14C, 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 
Supervisor.
    (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 
Supervisor.
    (5) Engines. (i) Engine exhaust. Engine exhausts shall be equipped 
to comply with the insulation and personnel protection requirements of 
API RP 14C, section 4.2c(4). Exhaust piping from diesel engines shall 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. Compressor installations shall be equipped with 
the following protective equipment as required in API RP 14C, sections 
A4 and A8.
    (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 designed 
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 Supervisor, 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, Fire Prevention and Control Open Type Offshore Production 
Platforms, and shall require approval of the District Supervisor. 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

[[Page 334]]

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 Supervisor.
    (iii) A firefighting system using chemicals may be used in lieu of a 
water system if the District Supervisor 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 Supervisor 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, 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 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 Supervisor may require the installation and 
maintenance of a gas detector or alarm in any potentially hazardous 
area.
    (v) Fire- and gas-detection systems shall be an approved type, 
designed and installed in accordance with API RP 14C, API RP 14G, and 
API RP 14F, Design and Installation of Electrical Systems for Offshore 
Production Platforms.
    (10) Electrical equipment. Electrical equipment and systems shall be 
designed, installed, and maintained in accordance with the requirements 
in Sec. 250.403 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

[[Page 335]]

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, compliance is not required with the provisions of API RP 
14C 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 Sec. 250.402 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]



Sec. 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 shall be in accordance with API RP 14C, Appendix D, 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 shall be tested at least once each 
calendar month, but at no time shall 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) 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 testing shall be in

[[Page 336]]

accordance with the test procedures specified in API RP 14H. 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.
    (5) 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 shall be tested for leakage 
in accordance with the test procedure specified in API RP 14C, appendix 
D, section D4, table D2, subsection D. 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.
    (6) 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.
    (7) All pumps for firewater systems shall be inspected and operated 
weekly.
    (8) 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.
    (9) All TSH devices shall be tested at least once every 12 months, 
excluding those addressed in paragraph (a)(6) 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.
    (10) 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.
    (11) Prior to the commencement of production, the lessee shall 
notify the District Supervisor when the lessee is ready to conduct a 
preproduction test and inspection of the integrated safety system. The 
lessee shall also notify the District Supervisor 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 Supervisor. 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]



Sec. 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.



Sec. 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

[[Page 337]]

    (ii) API Spec Q1, Specification for Quality Programs.
    (3) All SSV's and USV's must meet the technical specifications of 
API Spec 6A and 6AV1. All SSSV's must meet the technical specifications 
of API Spec 14A.
    (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, Engineering and Operations Division; 
Minerals Management Service; Mail Stop 4700; 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]



Sec. 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 Sec. 250.417 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]



                   Subpart I--Platforms and Structures



Sec. 250.900  General requirements.

    (a) The lessee shall design, fabricate, install, use, inspect, and 
maintain all platforms and structures (platforms) on the Outer 
Continental Shelf (OCS) to assure their structural integrity for the 
safe conduct of drilling, workover, and production operations, 
considering the specific environmental conditions at the platform 
location.
    (b) All new fixed or bottom-founded platforms (i.e., platforms or 
other structures, e.g., single-well caissons, artificial islands), shall 
be designed, fabricated, installed, inspected, and maintained in 
accordance with all the requirements of this section and Secs. 250.901 
and 250.904 through 250.914 of this subpart. Applications submitted 
pursuant to Sec. 250.901 shall require the approval by the Regional 
Supervisor prior to platform installation.
    (c) All new platforms which meet any of the conditions listed below 
shall be subject to the Platform Verification Program and shall be 
designed, fabricated, and installed in accordance with the requirements 
of Secs. 250.901 through 250.914 of this part.
    (1) Platforms installed in water depths exceeding 400 feet,
    (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.
    (d) Major modification to any platform shall be subject to the 
requirements of this subpart and shall require the approval of the 
Regional Supervisor. Major modification means any structural changes 
which materially alter the approved plan or causes a major deviation 
from approved operations.
    (e)(1) Major repairs of damage to any platform shall require the 
prior approval of the Regional Supervisor. Major repairs of damage means 
corrective operations involving structural members affecting the 
structural integrity of a portion or all of the platform.
    (2) Under emergency conditions, repairs to primary structural 
elements may be made to restore an existing permitted condition without 
prior approval. The Regional Supervisor shall

[[Page 338]]

be notified within 24 hours of the damage that occurred and repairs that 
were made. The Regional Supervisor's approval for repairs shall be 
obtained.
    (f) The requirements for an application for approval for the reuse 
or conversion of the use of an existing fixed or mobile platforms shall 
be determined on a case-by-case basis. An application shall be submitted 
to the Regional Supervisor for approval and shall include location, 
intended use, and demonstrate the adequacy of the design and structural 
condition of the platform.
    (g) In addition to the requirements of this subpart, platform 
design, fabrication, and installation shall conform to API RP 2A, 
Recommended Practice For Planning, Designing, And Constructing Fixed 
Offshore Platforms, or American Concrete Institute (ACI) 357R, Guide for 
the Design and Construction of Fixed Offshore Concrete Structures, as 
appropriate. Alternative codes or rules may be utilized with approval of 
the Regional Supervisor. The requirements contained in these documents 
(API RP 2A and ACI 357R) are incorporated herein insofar as they do not 
conflict with other provisions 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]



Sec. 250.901  Application for approval.

    (a) All applications under the provisions of this subpart shall be 
submitted to the Regional Supervisor for approval. All significant 
changes or modifications to approved applications shall be submitted to 
the Regional Supervisor for approval.
    (b) Applications for all new platforms or major modifications shall 
be submitted in triplicate and shall contain the following information:
    (1) General platform information including the following:
    (i) The platform designation, lease number, area name, and block 
number;
    (ii) Longitude and latitude coordinates, Universal Transverse 
Mercator grid-system coordinates, state plane coordinates in the Lambert 
or Transverse Mercator Projection system, and a plat drawn to a scale of 
1 inch = 2,000 feet showing surface location of the platform and 
distance from the nearest block lines;
    (iii) Drawings, plats, front and side elevations of the entire 
platform, and plan views that clearly illustrate essential parts, i.e., 
number and location of well slots, design loadings of each deck, water 
depth, nominal size and thickness of all primary load-bearing jacket and 
deck structural members, and nominal size, makeup, thickness, and design 
penetration of piling;
    (iv) Corrosion protection or durability details which consist of the 
corrosion-protection method; expected life; and durability criteria for 
the submerged, splash, and atmospheric zones; and
    (v) In the Alaska OCS Region, the following additional information 
shall be submitted:
    (A) Slope protection and berm elevation for manmade islands,
    (B) Wall thickness with size and placement of major steel 
reinforcement for concrete-gravity structures,
    (C) Shell thickness with size and location of major reinforcement 
members for steel-gravity structures, and
    (D) A plan for periodic inspections of the installed platforms in 
accordance with Sec. 250.912 of this part.
    (2) A summary of environmental data, as addressed in Sec. 250.904 of 
this part, which has a bearing on the platform's design, installation, 
and operation, e.g., wave heights and periods, current, vertical 
distribution of wind and gust velocities, water depth, storm and 
astronomical tide data, marine growth, snow and ice effects, and air and 
sea temperatures;
    (3) Foundation information including the following:
    (i) A geotechnical investigation report containing a brief summary 
of the major strata encountered at the location by bore holes presented 
in tabular form, a detailed subsurface profile illustrating results of 
field and laboratory testing, a listing of field and laboratory 
investigations and tests with a basic summary of resultant 
determinations, the identification of properties and conditions of the 
seabed and the subsoil, and the identification of any manmade hazards or 
obstructions;

[[Page 339]]

    (ii) A description of the effect of the environmental and functional 
loads on the foundation;
    (iii) A determination, with supporting information, of the 
susceptibility of the area to soil movement and, if susceptible, an 
analysis of slope and soil stability;
    (iv) A summary of the foundation design criteria as specified in 
Sec. 250.909 of this part; and
    (v) A summary of the seafloor survey results specified in 
Sec. 250.909(b)(2) of this part.
    (4) Structural information including the following:
    (i) The design life of the platform and the basis for such 
determination.
    (ii) A summary description of the design load conditions and design 
load combinations, taking into consideration the worst environmental and 
operational conditions anticipated over the service life of the 
platform.
    (iii) A listing and description of the appropriate material 
specifications.
    (iv) A description of the design methodologies, e.g., elastic, 
inelastic, and ultimate strength, used in design of the platform.
    (v) A summary of pertinent derived factors of safety against failure 
for major structural members, e.g., unity check ratios exceeding 0.85 
for steel-jacket platform members, indicated on ``line'' sketches of 
jacket sections.
    (vi)(A) In the Alaska, Atlantic, and Pacific OCS Regions, a summary 
of the fatigue analysis as specified in Secs. 250.905 through 250.909 of 
this part. The specific requirements for a fatigue analysis shall be 
determined by the Regional Supervisor on a case-by-case basis to 
determine the adequacy of the design and to assure the structural 
integrity of the platform.
    (B) In the Gulf of Mexico OCS Region, a summary of the fatigue 
analysis as specified in Secs. 250.905 through 250.909 of this part. A 
fatigue analysis shall be performed for each steel template, pile-
supported platform with natural periods greater than 3 seconds, and for 
each platform to be fabricated of high-strength steel (i.e., over 50 
thousand pounds per square inch minimum yield) where components of high-
strength steel are subjected to cyclic loading. The specific 
requirements for a fatigue analysis for other platforms shall be 
determined by the Regional Supervisor on a case-by-case basis to 
determine adequacy of the design and to assure the structural integrity 
of the platform.
    (c) The information shall be submitted with or subsequent to the 
submittal of an Exploration Plan or Development and Production Plan. 
Additional detailed data and information may be required by the Regional 
Supervisor when needed to determine the adequacy of the design.
    (d) The lessee shall have detailed structural plans as called for in 
paragraph (b)(1)(iii) of this section and specifications for new 
platforms or other structures and major modifications certified by a 
registered professional structural engineer or civil engineer 
specializing in structural design. The lessee shall also sign, date, and 
submit the following certification: Lessee certifies that the design of 
the structure/modification has been certified by a registered 
professional structural or a civil engineer specializing in structural 
design, and the structure/modification will be fabricated, installed, 
and maintained as described in the application and any approved 
modification thereto. Certified design and as built plans and 
specifications will be on file at------.
    (e) The lessee shall notify the Regional Supervisor at least 1 week 
prior to transporting the platform to the installation site.

[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 
29485, 29486, May 29, 1998; 64 FR 9065, Feb. 24, 1999]



Sec. 250.902  Platform Verification Program requirements.

    (a) Requirements. These requirements apply to the design, 
fabrication, and installation of new, fixed, bottom-founded, pile-
supported, or concrete-gravity platforms. The applicability of these 
requirements to other types of platforms shall be determined by the MMS 
on a case-by-case basis. For all new platforms or major modifications 
which meet any of the conditions contained in Sec. 250.900(c) of this 
part, the lessee shall submit the design, fabrication, and installation 
verification plans to the Regional Supervisor for approval

[[Page 340]]

in accordance with paragraph (b) of this section. The design plan shall 
be submitted with or subsequent to the submittal of an Exploration Plan 
or Development and Production Plan. The fabrication and installation 
plans shall be submitted and approval obtained before such operations 
are initiated.
    (b) Verification plan requirements. (1) General plan requirements. 
Each verification plan shall be submitted in triplicate and include the 
following:
    (i) A nomination of a Certified Verification Agent (CVA) who shall 
conduct specified reviews in accordance with Sec. 250.903 of this part,
    (ii) The CVA qualification statement consisting of the following:
    (A) Previous experience in third-party verification or experience in 
the design, fabrication, and/or installation of offshore oil and gas 
platforms, manmade islands, or other marine structures;
    (B) Technical capabilities of the individual or the primary staff to 
be associated with the CVA functions for the specific project;
    (C) Size and type of organization or corporation;
    (D) In-house availability of, or access to, appropriate technology, 
i.e., computer programs and hardware and testing materials and 
equipment;
    (E) Ability to perform the CVA functions for the specific project 
considering current commitments; and
    (F) Previous experience with MMS requirements and procedures.
    (iii) The level of work to be performed by the CVA, and
    (iv) A list of documents to be furnished to the CVA.
    (2) Design verification plan requirements. The design plan shall 
also include the following:
    (i) All design documentation specified in Sec. 250.901(b) of this 
part, and
    (ii) Abstracts of the computer programs used in the design process.
    (3) Fabrication verification plan requirements. The fabrication plan 
shall also include fabrication drawings and material specifications for 
artificial island structures, major members of concrete- and steel-
gravity structures, all the primary load-bearing members included in the 
space-frame analysis for jacket structures, and 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 (NDE) for 
welds and materials, and
    (vii) Quality assurance procedures.
    (4) Installation verification plan requirements. Additionally, the 
installation plan shall include a summary description of the planned 
marine operations, contingencies considered, alternate courses of 
action, and the inspections to be performed including a graphical 
identification of areas to be inspected and the acceptance/rejection 
criteria.
    (c) Requirements for resubmittal. All such plans or the appropriate 
part affected shall be resubmitted for approval if the CVA is changed, 
if the CVA's or assigned personnel's qualifications change, or if the 
level of work to be performed changes. The summary of technical details 
need not be resubmitted, unless changes are made in the technical 
details.
    (d) Combining of plans. For manmade islands or platforms fabricated 
and installed in place, the fabrication and installation verification 
plans shall be combined.

[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 
29486, May 29, 1998]



Sec. 250.903  Certified Verification Agent duties and nomination.

    (a) CVA duties. The CVA nominated by the lessee and approved by the 
Regional Supervisor shall conduct the appropriate reviews in accordance 
with the following:
    (1) Design phase. (i) The CVA shall conduct the design verification 
to ensure that the proposed platform or major modification has been 
designed to withstand the maximum environmental and functional load 
conditions anticipated during the intended service life at the proposed 
location.
    (ii) The design verification shall be conducted by, or be under the 
direct

[[Page 341]]

supervision of, a registered professional civil or structural engineer.
    (iii) The CVA shall consider the applicable provisions of 
Secs. 250.904 through 250.911 of this part and use good engineering 
practice in conducting an independent assessment of the adequacy of all 
proposed planning criteria, environmental data, load determinations, 
stress analyses, material designations, soil and foundation conditions, 
safety factors, and other pertinent parameters of the proposed design.
    (iv) Interim reports shall be submitted by the CVA, as appropriate, 
to the Regional Supervisor and the lessee.
    (v) Upon completion of the design verification, a final report shall 
be prepared which summarizes the material reviewed by the CVA and the 
findings and includes a recommendation that the Regional Supervisor 
either accept, request modification(s), or reject the proposed design. 
In addition, the report shall include the particulars of how, by whom, 
and when the independent review was conducted and any special comments 
considered necessary. The final report shall be submitted to the lessee 
and, in triplicate, to the Regional Supervisor within 6 weeks of the 
receipt of the design data or from the date the approval to act as a CVA 
was issued, whichever is later.
    (2) Fabrication verification. The CVA shall monitor the fabrication 
of the platform or major modification to ensure that it has been built 
in accordance with the approved design plans and specifications and the 
fabrication plan, including the following:
    (i) Periodic onsite inspections shall be made while fabrication is 
in progress. The following of the fabrication items, as appropriate, 
shall be verified:
    (A) Quality control by lessee and builder,
    (B) Fabrication site facilities,
    (C) Material quality and identification methods,
    (D) Fabrication procedures specified in the approved plan and 
adherence to such procedures,
    (E) Welder and welding procedure qualification and identification,
    (F) Structural tolerances specified and adherence to those 
tolerances,
    (G) The NDE requirements and evaluation results of the specified 
examinations,
    (H) Destructive testing requirements and results,
    (I) Repair procedures,
    (J) Installation of corrosion-protection systems and splash-zone 
protection,
    (K) Erection procedures to ensure that overstressing of structural 
members does not occur,
    (L) Alignment procedures,
    (M) Dimensional check of the overall structure, and
    (N) Status of quality-control records at various stages of 
fabrication.
    (ii) The CVA shall consider the applicable provisions of 
Secs. 250.904 through 250.911 of this part and use good engineering 
practice in conducting an independent assessment of the adequacy of the 
fabrication of the platform or major modification.
    (iii) Interim reports shall be submitted by the CVA, as appropriate, 
to the Regional Supervisor and the lessee.
    (iv) If the CVA finds that fabrication procedures are changed or 
design specifications are modified, the lessee shall be informed. If the 
lessee prefers to accept the modifications as informed by the CVA, the 
Regional Supervisor shall also be informed.
    (v) A final report shall be prepared by the CVA covering the 
adequacy of the entire fabrication phase giving details of how, by whom, 
and when the independent monitoring activities were conducted and 
providing any special comments considered necessary. The final report is 
not required to cover aspects of the fabrication already included in 
interim reports. The final report shall describe the CVA's activities 
during the verification process, summarize the findings, contain a 
confirmation or denial of compliance with the design specifications and 
the approved fabrication plan, and a recommendation to accept or reject 
the fabrication. The report shall be submitted to the lessee and, in 
triplicate, to the Regional Supervisor immediately after completion of 
the fabrication of the platform.
    (3) Installation phase. The CVA shall witness the loadout of the 
jacket, deck(s), and piles from the fabrication

[[Page 342]]

site(s); review the towing records; conduct an onsite survey after 
transportation to the approved location; witness the actual installation 
of the platform or major modification; determine that the platform has 
been installed at the approved location in accordance with the approved 
design and the installation plan; and shall comply with the following:
    (i) The CVA shall consider the applicable provisions of 
Secs. 250.904 through 250.911 of this part and use good engineering 
practice in conducting an independent assessment of the adequacy of the 
installation activities. The following parts of the overall installation 
process, as appropriate, shall be verified:
    (A) Loadout and initial flotation operations, if any;
    (B) Towing operations to the specified location;
    (C) Launching and uprighting operations;
    (D) Submergence operations;
    (E) Pile installation; and
    (F) Final deck and/or component installation.
    (ii) The CVA shall observe the installation activities, spot-check 
equipment, procedures, and recordkeeping, as necessary, to determine 
compliance with Secs. 250.904 through 250.911 of this part and the 
approved plans, and immediately report to the Regional Supervisor and 
the lessee any discrepancies or damage to structural members. Approval 
for modified installation procedures or for major deviation from 
approved installation procedures shall be obtained from the Regional 
Supervisor.
    (iii) Interim reports shall be submitted by the CVA, as appropriate, 
to the Regional Supervisor and the lessee.
    (iv) A final report shall be prepared by the CVA covering the 
adequacy of the entire installation phase giving details of how, by 
whom, and when the independent monitoring activities were conducted and 
providing any special comments considered necessary. The final report 
shall describe the CVA's activities during the verification process, 
summarize the findings, contain a confirmation or denial of compliance 
with the approved installation plan, and a recommendation to accept or 
reject the installation. The report shall be submitted to the lessee 
and, in triplicate, to the Regional Supervisor within 2 weeks of 
completion of the installation of the platform.
    (4) All data provided to the CVA shall be handled in the strictest 
confidence and not be released by the CVA without the consent of the 
lessee.
    (5) Individuals or organizations acting as CVA's for a particular 
platform shall not function in any capacity other than that of a CVA for 
that specific project, whenever the additional activities would create a 
conflict, or appearance of a conflict of interest.
    (b) CVA nomination. (1) Nomination. Individuals or organizations 
shall be nominated by the lessee planning to use their services. The 
lessee shall specify whether the nomination is for the design, 
fabrication, or installation phase of verification; for two phases; or 
for all three phases.
    (2) Qualifications. Qualification submissions shall contain 
sufficient information to determine compliance with 
Sec. 250.902(b)(1)(ii) of this part.

[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 
29486, May 29, 1998]



Sec. 250.904  Environmental conditions.

    (a) General. The performance standards of this section pertain to 
all platforms covered by these requirements regardless of the 
fabrication material.
    (1) Environmental considerations. All environmental phenomena 
appropriate to the areas of fabrication, transportation, and 
installation of an offshore platform shall be considered and their 
influence on the platform accounted for. Such phenomena shall include 
wind, waves, current, temperature, tide, marine growth, chemical 
components of air and water, snow and ice, earthquakes, tsunami, seiche, 
and other appropriate phenomena.
    (2) Environmental data. Statistical data and defensible statistical 
and mathematical models shall be employed to describe the range of 
pertinent expected variations of environmental phenomena. Defensible 
data supplied by meteorologists, oceanographers, or other appropriate 
specialists are acceptable as the basis for design. Where possible, 
environmental phenomena shall be described by the

[[Page 343]]

characteristic parameters most relevant in the evaluation of effects on 
the platform.
    (b) Statistical methods. (1) When statistical methods are employed 
in the determination of parameters characterizing environmental 
phenomena, the statistical methods and distributions employed shall be 
appropriate to their application as evidenced by relevant statistical 
tests, confidence limits, and other measures of statistical 
significance.
    (2) Short-term and long-term variations of environmental phenomena 
such as wind, waves, and current shall be described by statistical 
distributions relevant to the parameter considered. Defensible 
statistical modeling techniques shall be used in the prediction of 
extreme values.
    (3) When hindcasting techniques are employed to approximate 
environmental parameters, the validity of the model used shall be 
defensible.
    (c) Design considerations. (1) General. A thorough assessment of the 
environment in the vicinity of the installation site shall be made to 
determine the conditions expected to occur at the site over the life of 
the platform.
    (2) Design environmental condition. (i) ``Design environmental 
condition'' means the environmental factors producing the most 
unfavorable effects on the platform. Parameters describing the design 
environmental condition are given in paragraphs (c)(2)(ii) (A), (B), and 
(C) of this section.
    (ii) The design environmental condition shall reflect the various 
environmental events that individually or collectively represent the 
most severe conditions the platform is anticipated to experience. Such 
conditions shall be formulated with a set of parameters that describe 
the relevant environmental events, including the following:
    (A) The maximum wave corresponding to a selected recurrence period 
together with the associated wind, current, and appropriate ice and snow 
effects;
    (B) The minimum air and sea temperatures appropriate to the event 
being treated; and
    (C) The maximum water level due to tide and storm surge.
    (iii) Consideration shall be given to other combinations of the 
parameters specified in paragraph (c)(2)(ii)(A) of this section 
involving either maximum wind, maximum current, or maximum ice load 
which may cause a greater response of the platform.
    (iv) In general, the recurrence period chosen for the events 
specified in paragraphs (c)(2)(ii) (A) and (C) of this section shall 
primarily be based on the design service life of the platform. For 
platforms designed for a service life of 20 years, the recurrence period 
chosen for the determination of these events shall not be less than 100 
years. For other service lives, the design event recurrence interval 
shall generally be adjusted to provide for a risk of occurrence which 
does not exceed the risk of occurrence for the 20-year/100-year 
combination.
    (v) For installation sites located in seismically active areas, see 
paragraph (d)(8) of this section.
    (3) Operating environmental conditions. Operating environmental 
conditions means the set of characteristic parameters of environmental 
conditions associated with a normal function or operation to be 
conducted on the platform. For each such intended normal function or 
operation, the lessee shall determine a set of characteristic parameters 
of environmental conditions.
    (d) Specific environmental conditions. (1) Waves information 
including the following:
    (i) Wave conditions considered for design shall be described by 
defensible statistical and/or deterministic methods.
    (ii) Parameters characterizing design environmental waves shall be 
based on wave statistics or the results of defensible analytic 
prediction methods such as hindcasting techniques.
    (iii) When using probabilistic analyses, the probability of 
occurrence of various wave-height groups classified by directionality 
and for a wide range of possible periods (i.e., tables of exceedance) 
shall be determined. Where required by the method selected to predict 
extreme values, the average duration of various wave-height groups 
(i.e., persistence data) shall be determined. All extrapolations and 
long-

[[Page 344]]

term wave data analyses shall use defensible techniques, and available 
data on extreme values measured in the vicinity of the site shall be 
included in the long-term prediction.
    (iv) When using deterministic methods, waves shall be described by 
the parameters, height, period, and other relevant shape 
characteristics. The design-wave formulation used shall be valid for the 
problem considered.
    (v) Breaking-wave criteria appropriate to the installation site 
shall be determined using defensible formulations.
    (vi) If spectral wave data are established for the dynamic analysis 
of structural response to waves, such data shall be derived in 
accordance with defensible methods. If spectral data are not available 
in adequate quantities for the intended application, defensible 
mathematical formulations that best fit the available data shall be 
used.
    (2) Wind information including the following:
    (i) Wind velocities shall be classified on the basis of their 
duration. Wind velocities having a duration of less than 1 minute are 
referred to as gust winds. Wind velocities having a duration equal to or 
greater than 1 minute are referred to as sustained winds. The reference 
elevation is 33 feet above still-water level.
    (ii) Wind conditions considered for design shall be described by 
defensible statistical or deterministic methods.
    (iii) Wind profiles shall be determined on the basis of defensible 
statistical or mathematical models. Corrections of wind velocity data to 
averaging periods other than those employed in the collections of data 
shall be based on defensible methods.
    (iv) Distribution of the direction and speed of wind approach to the 
platform shall be determined, or alternatively, winds shall be 
considered to approach from any direction.
    (3) Current information including the following:
    (i) Current velocities to be used in design shall be determined on 
the basis of the best statistics available. Tidal current, wind-
generated current, density current, circulation current, and river-
outflow current shall be combined on the basis of their probability of 
simultaneous occurrence in arriving at current velocities to be used in 
design.
    (ii) Current velocity profiles shall be determined on the basis of 
site-specific studies or defensible empirical relationships. Unusual 
profiles due to bottom currents and stratified effects in regions near 
the mouth of large rivers shall be accounted for.
    (iii) Directional data on currents which exist in the absence of 
waves shall be described for each month or by season. Unless a detailed 
study of current directions is made, currents shall be assumed to run in 
any direction.
    (4) Tide information including the following:
    (i) The design storm-tide elevation shall be identified for the 
installation site. For design purposes, the design environmental wave 
height shall be superimposed on the storm-tide elevation.
    (ii) Variations in the elevation of the daily lunar tide shall be 
used in determining the elevations of boat landings, barge fenders, and 
the corrosion-prevention treatment of platforms in the splash zone (see 
Sec. 250.906(c)(5) of this part).
    (iii) The assumed maximum or storm tide shall include astronomical 
tide, wind tide, and pressure-induced storm surge. Minimum-tide 
estimates shall be based on either the astronomical or lunar tide only. 
The water depth shall be referenced to a datum (e.g., mean low/water or 
mean low low/water) consistent with all other references to elevations 
and depths.
    (iv) If data directly applicable to the installation site are not 
available, the best estimate based on data for nearby locations shall be 
used.
    (5) Temperature information including the following:
    (i) Extreme values of low temperatures shall be expressed in terms 
of the most probable, lowest values with their corresponding recurrence 
periods;
    (ii) Air, sea surface, and seabed temperatures shall be accounted 
for in describing the environment and in justifying the temperatures 
used in design.
    (6) Snow and ice information including the following:
    (i) If the platform is to be located in an area where sea ice may 
develop or drift, ice conditions shall be accounted

[[Page 345]]

for. Data shall be derived from actual field investigations, laboratory 
analyses, or other appropriate analogous sources;
    (ii)(A) Relevant statistical and physical data on the sea-ice and 
snow conditions shall be described with particular attention to the 
following:
    (1) Concentration and distribution of ice and snow,
    (2) Morphology of sea ice (e.g., ice floes, ice ridges, or rafted 
ice),
    (3) Mechanical properties of ice (mode of failure),
    (4) Drift speed and direction,
    (5) Thickness of ice and keel depth of pressure ridges, and
    (6) Probability of encountering icebergs, ice floes, ice-floe 
fragments, and hummocks.
    (B) The weight of the maximum snow and ice anticipated to accumulate 
on the platform shall be determined.
    (7) Marine growth information including the following:
    (i) When assessing the potential for marine growth, account shall be 
taken of relevant observations and experience in the area. In the 
absence of such information, defensible analytical techniques shall be 
employed to assess the potential for marine growth. These techniques 
shall take into account salinity, oxygen content, hydrogen-ion 
concentration value, current, temperature, water turbidity, and other 
appropriate factors.
    (ii) Consideration shall be given to the selection of surface 
coatings which resist breakdown by micro-organisms which reduce the 
onset of corrosion.
    (iii) Particular attention shall be paid to the effects that marine 
growth has on surface roughness characteristics of submerged structural 
members.
    (8) Earthquake information including the following:
    (i) The effects of earthquakes on platforms located in areas known 
to be seismically active shall be addressed.
    (ii) Except for the provision of Sec. 250.905(d)(5)(ii) of this 
part, the seismicity of the site shall be determined. Preferably, this 
shall be based on site-specific data. However, regional data shall be 
deemed acceptable for use when site-specific data are not available and 
the regional data are interpreted in a manner to produce the most 
adverse effect on a platform at the specific site. The following data 
shall be obtained:
    (A) Recurrence interval of seismic events appropriate to the design 
life of the structure,
    (B) Proximity to active faults,
    (C) Type of faulting,
    (D) Attenuation of ground motion between the faults and the site,
    (E) Subsurface soil conditions, and
    (F) Records from past seismic events at the site or from analogous 
sites.
    (iii) The use of available data to describe the seismic 
characteristics of the site is permitted where it can be shown that such 
data are consistent with the requirements of paragraph (d)(8)(ii) of 
this section.
    (iv) The seismic data shall be used to establish a quantitative 
design earthquake criterion describing the design earthquake-induced 
ground motion. In addition to ground motion and as applicable to the 
installation site, the following earthquake-related phenomena shall be 
taken into account:
    (A) Liquefaction of subsurface soils,
    (B) Submarine slides,
    (C) Tsunamis, and
    (D) Fluid motions in tanks.

[53 FR 10690, Apr. 1, 1988; 53 FR 26067, July 11, 1988. Redesignated and 
amended at 63 FR 29479, 29486, May 29, 1998]



Sec. 250.905  Loads.

    (a) Introduction. This section covers the identification, 
definition, and determination of the loads to which a fixed offshore 
platform may be exposed during and after its transportation and 
installation. The requirements contained in paragraphs (b) through (d) 
of this section apply to both steel-piled platforms and concrete-gravity 
platforms. Additional requirements covering steel-piled platforms are 
contained in paragraph (e) of this section. Additional requirements 
covering concrete-gravity platforms are contained in paragraph (f) of 
this section.
    (b) General. (1) All types of loads specified in paragraphs (c)(1) 
through (c)(5) of this section shall be accounted for in the design and 
operation of the platform.
    (2) Where applicable, the effects of increased dimensions and weight 
due to

[[Page 346]]

marine growth and snow and ice accumulation shall be addressed in the 
design.
    (c) Load definition. (1) Dead loads. Dead loads associated with the 
platform are loads that do not change during the mode of operation under 
consideration. Dead loads include the following:
    (i) Weight in the air of the platform (refer to paragraphs (e)(1) 
and (f)(1) of this section for itemizations of weight for pilefounded 
platforms and gravity platforms, respectively).
    (ii) Weight of permanent ballast and the weight of permanent 
machinery including liquids at operating levels.
    (iii) External hydrostatic pressure and buoyancy in calm sea 
conditions calculated on the basis of the design waterline.
    (iv) Static earth pressure.
    (2) Live loads. Live loads associated with the normal operation and 
use of the platform are loads that could change during the mode of 
operation considered. Live loads acting after fabrication or 
installation include the following:
    (i) Weight of drilling and production equipment that can be removed 
such as derrick, draw works, mud pumps, mud tanks, separators, and 
tanks.
    (ii) Weight of crew and consumable supplies such as mud, chemicals, 
water, fuel, pipe, cable, stores, drill stem, and casing.
    (iii) Weight of liquids in storage tanks.
    (iv) Forces exerted on the platform due to drilling, e.g., the 
maximum derrick reaction when placing or pulling casing.
    (v) The forces exerted on the platform during the operation of 
cranes and vehicles.
    (vi) The forces exerted on the platform by vessels moored to the 
platform.
    (vii) The forces exerted on the platform by helicopters during 
takeoff and landing or while parked on the platform. When applicable, 
the dynamic effects on the platform of the forces specified in 
paragraphs (c)(2) (iv) through (vii) of this section shall be taken into 
account. Live loads occurring during transportation and installation 
shall be determined for each specific operation involved, and the 
dynamic effects of such loads shall be addressed (see Sec. 250.910 of 
this part).
    (3) Deformation loads. Deformation loads are loads due to 
deformations imposed on the platform. For an itemization of deformation 
loads applicable to steel-piled platforms and concretegravity platforms, 
see paragraphs (e)(2) and (f)(2) of this section, respectively.
    (4) Accidental loads. Consideration shall be given to accidental 
loadings; and where such loadings are determined to be a factor, they 
shall be quantified and incorporated into the design. Accidental loads 
are loads that could occur as the result of an accident or exceptional 
conditions, such as the following:
    (i) Extreme impact loads caused by supply boats, barges, and other 
craft anticipated to work in the vicinity of the platform;
    (ii) Impact loads caused by dropped objects, such as drill collars, 
casing, blowout-preventer stacks;
    (iii) Loss of internal pressure required to resist hydrostatic 
loading and to maintain buoyancy during the installation of the 
platform;
    (iv) Explosion;
    (v) Effects of fire; and
    (vi) Iceberg collision.
    (5) Environmental load information including the following:
    (i) Environmental loads are loads due to wind, waves, current, ice, 
snow, earthquake, and other environmental phenomena.
    (ii) The characteristic parameters defining an environmental load 
shall be appropriate to the installation site as determined by the 
studies required by Sec. 250.904 of this part. Operating environmental 
loads are loads derived from the parameters characterizing operating 
environmental conditions (see Sec. 250.904(c)(3) of this part). Design 
environmental loads are loads derived from the parameters characterizing 
the design environmental condition (see Sec. 250.904(c)(2) of this 
part).
    (iii) Environmental loads shall be applied to the platform from 
directions producing the most unfavorable effects on the platform unless 
site-specific studies allow for a less stringent requirement.

[[Page 347]]

    (iv) The combination and severity of design environmental loads 
shall be consistent with the likelihood of their simultaneous 
occurrence. The simultaneous occurrence of environmental loads shall be 
modeled by appropriate superposition methods.
    (v) Earthquake loads and loads resulting from accidental or rare 
environmental phenomena need not be combined with other environmental 
loads unless site-specific conditions indicate that such combination is 
appropriate.
    (d) Determination of environmental loads. (1) Wave load information 
including the following:
    (i) Wave-induced loads shall be calculated using defensible methods 
or shall be obtained from adequate model or field test data;
    (ii) A sufficient range of waves and wavecrest positions relative to 
the platform shall be investigated to ensure an accurate determination 
of the maximum wave load on the platform;
    (iii) Wave impact loads on structural members below the design wave 
crest elevation shall be accounted for by defensible theoretical methods 
or relevant model test of full-scale data;
    (iv) Where applicable, the possibility of dynamic excitation of the 
platform due to flow-induced cyclic loading shall be addressed;
    (v) For additional requirements pertaining to steel-piled platforms 
and concrete gravity-platforms, see paragraphs (e)(3) and (f)(3) of this 
section, respectively; and
    (vi) Where applicable, additional hydrostatic loading effects shall 
be addressed.
    (2) Wind load information including the following:
    (i) Wind loads, local wind pressures, and wind profiles shall be 
determined on the basis of defensible analytical methods or wind tunnel 
tests on a representative model of the platform,
    (ii) In determining design environmental loads on the overall 
platform, wind loads calculated on the basis of the design-sustained 
wind velocity shall be combined with other design environmental loads,
    (iii) The design gust wind load shall be used in the design of local 
structure unless the effects of the load combination described in 
paragraph (d)(2)(ii) of this section are more severe,
    (iv) Where appropriate, the dynamic effects due to the cyclic nature 
of gust wind and cyclic loads due to vortex shedding shall be taken into 
account. Both the drag and lift components of loads due to vortex 
shedding shall be taken into account.
    (v) Where appropriate, flutter and load amplification due to vortex 
shedding shall be addressed.
    (3) Current load information including the following:
    (i) Current-induced loads on immersed members of the platform shall 
be accounted for by defensible methods or the results of model test or 
site-specific data,
    (ii) The lift and drag coefficients used in the determination of 
current loads shall be appropriate to the current velocity and 
structural configuration,
    (iii) Current velocity profiles used in design shall be appropriate 
to the installation site,
    (iv) For determination of loads induced by the simultaneous 
occurrence of wave and current fields, the total velocity field shall be 
computed by defensible methods before computing the total force, and
    (v) Where appropriate, flutter and load amplification due to vortex 
shedding shall be addressed.
    (4) Ice and snow load information including the following:
    (i) For platforms located in areas associated with ice movement, 
contact loads caused by floating ice shall be determined according to 
defensible theoretical methods, model test data, or full-scale 
measurements;
    (ii) In locations where platforms are subject to ice and snow 
accumulation, the additional weight of snow and ice on the platform 
shall be addressed;
    (iii) The effects of ice accumulation and ice jam, including the 
effects of changes in configuration due to adhesion, shall be accounted 
for in the determination of the total environmental load; and
    (iv) The incident pressure due to pack ice, pressure ridges, and 
where appropriate, ice island fragments impinging on the platform shall 
be addressed.
    (5) Earthquake load information including the following:

[[Page 348]]

    (i) For platforms located in seismically active areas, design 
earthquake-induced ground motions shall be determined on the basis of 
seismic data applicable to the installation site. Design earthquake 
ground motions shall be described by either applicable ground motion 
records or response spectra consistent with the recurrence period 
appropriate to the design life of the platform.
    (ii) Available and defensible standardized spectra applicable to the 
region of the installation site are acceptable if such spectra reflect 
those site-specific conditions affecting frequency content and energy 
distribution. These conditions include the type of active faults in the 
region, the proximity of the site to the potential source faults, the 
attenuation or amplification of ground motion between the faults and the 
site, and the soil conditions at the site.
    (iii) Ground-motion descriptions shall consist of three components 
corresponding to two orthogonal horizontal directions and the vertical 
direction. All three components shall be applied to the platform 
simultaneously.
    (iv)(A) When the response spectrum method is used for structural 
analysis, input values of ground motion (spectral acceleration 
representation) shall not be less severe than the following:
    (1) One hundred percent in a principal horizontal direction,
    (2) Sixty-seven percent in the orthogonal horizontal direction, and
    (3) Fifty percent in the vertical direction.
    (B) The horizontal components shall also be applied in the 
alternative orthogonal horizontal directions.
    (v) If the time history method is used for structural analysis, at 
least three sets of ground-motion time histories shall be employed. The 
manner in which the time histories are used shall account for the 
potential sensitivity of the platform's response to variations in the 
phasing of the ground-motion records.
    (vi) When applicable, effects of soil liquefaction and/or loads 
resulting from submarine slides or creep, tsunamis, and earthquake 
motions shall be addressed.
    (e) Loads on steel pile-supported platforms. The following 
requirements apply to loads on steel pile-supported platforms and shall 
be applied together with the requirements in paragraphs (b), (c), and 
(d) of this section:
    (1) The dead load of the platform shall include, as appropriate, the 
weight in air of the jacket, piling, grout, superstructure modules, 
stiffeners, decking, piping, heliport, and any other fixed structural 
part less buoyancy, with due allowance for flooding.
    (2) Where appropriate, the deformation loads to be accounted for are 
those resulting from temperature variations leading to thermal stresses 
in the platform, and those resulting from soil displacements (e.g., 
differential settlements or lateral displacements).
    (3) Wave load information including the following:
    (i) For platforms composed of members having diameters that are 
negligible in relation to the wave lengths considered, semiempirical 
formulations accounting for wave-induced drag and inertia forces based 
on the water particle velocities and accelerations on an undisturbed, 
incident flow field are acceptable;
    (ii) When a method as described in paragraph (e)(3)(i) of this 
section is used, the wave field shall be described by a defensible wave 
theory appropriate to the wave heights, wave periods, and water depth at 
the installation site;
    (iii) The coefficients of drag and inertia used in calculating wave 
loads shall be determined on the basis of model test results, published 
data, or full-scale measurements appropriate to the structural 
configuration, surface roughness, and wave field; and
    (iv) For platforms composed of members whose diameters are not 
negligible in relation to the wave lengths considered and for structural 
configurations that will substantially alter the undisturbed, incident 
flow field, diffraction forces and the hydrodynamic interaction of 
structural members shall be taken into account.
    (f) Loads on concrete-gravity platforms. The following requirements 
apply to loads on concrete-gravity platforms and shall be applied 
together with the

[[Page 349]]

requirements described in paragraphs (b), (c), and (d) of this section.
    (1) The dead load of the platform shall include, as appropriate, the 
weight in air of the foundation, skirts, columns, superstructure 
modules, decking, piping, heliport, and any other fixed structural part 
less buoyancy with due allowance for flooding. Weight calculations based 
on nominal dimensions and mean values of density are acceptable.
    (2) The deformation loads to be accounted for are those due to 
prestress, shrinkage and expansion, creep, temperature variations, and 
differential settlements.
    (3) Wave load information including the following:
    (i) For platforms composed of large gravity bases and one or more 
columns whose diameters are not negligible in relation to the wave 
lengths considered, defensible wave-load theories which account for the 
drag, inertia, and diffraction forces on the platform shall be employed;
    (ii) For complex structural configurations, the hydrodynamic 
interaction of large, immersed structural members shall be addressed;
    (iii) When diffraction forces and hydrodynamic interaction are 
negligible, only semiempirical formulations comparable to those 
mentioned in paragraphs (e)(3) (i) and (iii) of this section accounting 
for drag and inertia forces are acceptable; and
    (iv) The undisturbed, incident flow field shall be addressed by a 
defensible wave theory appropriate to the wave heights, wave periods, 
and water depth at the installation site.

[53 FR 10690, Apr. 1, 1988; 53 FR 26067, July 11, 1988. Redesignated and 
amended at 63 FR 29479, 29486, May 29, 1998]



Sec. 250.906  General design requirements.

    (a) General. This section specifies the general concepts and methods 
of analysis to be incorporated in the design of a platform.
    (b) Analytical approaches. (1) Structural response information 
including the following:
    (i) Methods of analysis employed in association with the 
specifications of these requirements shall treat geometric and material 
nonlinearities in a defensible manner. When nonlinear methods of 
analysis are used to assess collapse mechanisms, it shall be 
demonstrated that the platform has sufficient ductility to develop the 
required resistance or structural displacements.
    (ii) Where theoretically based analytical procedures covering the 
platform or parts thereof are unavailable or not well defined, model 
studies shall be utilized. The acceptability of model studies depends on 
the procedures employed, including enumeration of the possible sources 
of errors, the limits of applicability of the model test results, and 
the methods of extrapolation to full-scale data.
    (2) Loading format information including the following:
    (i) Either a deterministic or spectral format shall be employed to 
describe various load components. When a static approach is used, it 
shall be demonstrated, where appropriate, that the general effects of 
dynamic amplification were addressed. The influence of waves other than 
the highest waves shall be investigated for their potential to produce 
maximum peak stresses resulting from possible resonance with the 
platform.
    (ii) When considering the design earthquake as discussed in 
Sec. 250.905 of this part, a dynamic analysis shall be performed. A 
dynamic analysis shall also be performed to assess the effects of 
environmental or other types of loads if significant dynamic 
amplification is expected.
    (iii) For fatigue analysis, the long-term distribution of the stress 
range, with proper consideration of dynamic effects, shall be obtained 
for relevant loadings anticipated during the design life of the platform 
(see Secs. 250.907(c)(6) and 250.908(c)(6) of this part).
    (3) Combinations of loading components information including the 
following:
    (i) Loads imposed during and after installation shall be taken into 
account. Of the various loads described in Sec. 250.905, of this part, 
those loads to be considered for design shall be combined in a manner 
consistent with their probability of simultaneous occurrence. However, 
earthquake loadings shall be applied without consideration of other

[[Page 350]]

environmental effects unless conditions at the site necessitate their 
inclusion. The direction of applied environmental loads shall be that 
producing the highest possible influences on the platform, considering 
the platform's orientation and location with respect to bottom 
topography, direction of fetch, and nearby land masses.
    (ii) While it is required to obtain and use those loading components 
which produce realistic maximum effects on the platform, loading 
combinations corresponding to conditions after installation shall 
reflect both operating and design environmental loadings. Sections 
250.907, 250.908, and 250.909 of this part give the minimum load 
combinations to be considered.
    (iii) The operating environmental conditions and the maximum 
tolerable environmental loads during installation shall be specified.
    (c) Overall design considerations. (1) Design life. The design 
service life of the platform shall be specified as prescribed in 
Sec. 250.904(c)(2)(iv) of this part.
    (2) Air gap. An air gap of 5 feet shall be provided between the 
maximum crest elevation of the design wave (including tidal effects) and 
the lowest portion of the platform upon which wave forces have not been 
included in the design. After accounting for the initial and long-term 
settlements resulting from consolidation and subsidence, the elevation 
of the crest of the design wave shall be based on the elevation of the 
mean low-water line, astronomical and storm tides, wave runup, the 
tilting of the platform, and where necessary, tsunamis.
    (3) Long-term and secondary effects. The following effects shall be 
addressed, as appropriate, for the planned platform:
    (i) Local vibration due to machinery, equipment, and vortex 
shedding;
    (ii) Stress concentrations at critical joints;
    (iii) Secondary stresses induced by large deflections (P- 
effects);
    (iv) Cumulative fatigue;
    (v) Corrosion;
    (vi) Marine growth; and
    (vii) Ice abrasion.
    (4) General arrangement. The platform and equipment shall be 
arranged to minimize the potential of structural damage and personal 
injury resulting from accidents. In this regard, the consequences of the 
arrangement or placement of the following components and their effects 
shall be addressed:
    (i) Equipment and machinery--noise and vibration,
    (ii) High-pressure piping--leakage in closed spaces,
    (iii) Lifting devices--dropped loads, and
    (iv) Vessel mooring devices--line breakage and tripping quick-
release mechanisms.
    (5) Corrosion-protection zones. Measures taken to mitigate the 
effects of corrosion as required by Secs. 250.907(d) and 250.908(c)(5) 
of this part shall be specified and described in terms of the following 
definitions for corrosion-protection zones:
    (i) Submerged zone--that part of the platform below the splash zone,
    (ii) Splash zone--that part of the platform between the highest and 
lowest water levels reached by sea states exceeded for 1 percent of the 
time annually when superimposed on the highest and lowest levels of tide 
with due allowance for high and low installation of the platform,
    (iii) Atmospheric zone--that part of the platform above the splash 
zone,
    (iv) Ice zone--that part of the platform which can reasonably be 
expected to come into contact with floating or submerged ice annually.

[53 FR 10690, Apr. 1, 1988; 53 FR 26067, July 11, 1988. Redesignated and 
amended at 63 FR 29479, 29486, May 29, 1998; 63 FR 34597, June 25, 1998]



Sec. 250.907  Steel platforms.

    (a) Materials--(1) General. (i) This section covers specifications 
for materials used for the construction of steel pile-supported 
platforms. Steels shall be suitable for their intended service as 
demonstrated by testing under relevant service conditions or previous 
satisfactory performance under service conditions similar to those 
intended. Steels shall be of good commercial quality, defined by 
specification, and free of injurious defects.

[[Page 351]]

    (ii) Steels shall exhibit satisfactory formability and weldability 
characteristics and fracture toughness satisfactory for the intended 
applications. Materials for structural members which are fracture 
critical or for members which sustain significant tensile stress and 
whose fracture would pose a threat to the survival of the platform shall 
have sufficient toughness to guard against brittle fracture. Materials 
selected for members which are subjected to significant tensile stress 
shall have toughness suitable to their intended application.
    (iii) In cases where principal loads from either service or weld 
residual stresses are imposed normal to the plate, appropriate 
precautions shall be taken to avoid lamellar tearing parallel to the 
plate surface.
    (2) Material selection information including the following:
    (i) Steels for structural members shall be selected according to 
criteria that take into account the required yield strength, fracture 
toughness, service temperature (see paragraph (a)(3) of this section), 
and intended application;
    (ii) Bolts and nuts shall have mechanical and corrosion properties 
comparable to the structural elements being joined. Materials for bolts 
and nuts shall be defined by and tested in accordance with material 
standards compatible with those for the joined structural members;
    (iii) When new alloys are used, the adequacy of fracture toughness 
shall be supported by appropriate fracture tests; and
    (iv) When materials other than steel are used for structural 
purposes, the mechanical and durability properties necessary for their 
intended function shall be designated, including toughness and fatigue 
characteristics, where necessary.
    (3) Service temperature. Service temperature means the temperature 
that the material is expected to achieve in the operational environment.
    (i) For material at or below the waterline, the minimum service 
temperature shall be the lowest average daily water temperature 
applicable to the particular depth. For material above the waterline, 
the minimum service temperature shall be the lowest 1-day average daily 
atmospheric temperature over a 10-year period, unless the material is 
warmed by auxiliary heating.
    (ii) In all cases where material temperature is reduced by localized 
cryogenic storage or other cooling means, such factors shall be 
accounted for in establishing minimum service temperature.
    (4) Classification of applications. When considering the welding 
requirements given in subsequent sections, materials shall be considered 
as ``Weld Class A'' if the members are critical or special structural 
elements, ``Weld Class B'' if the members are primary load-carrying 
members of the platform, or ``Weld Class C'' if the members are 
secondary structural elements.
    (5) Material designation. All material employed in platform 
construction shall be described and designated by a material 
specification.
    (b) Fabrication and welding--(1) General. (i) Welding shall be 
performed in accordance with the applicable provisions of the American 
Welding Society (AWS) publication, AWS D1.1, Structural Welding Code--
Steel, or other appropriate welding codes.
    (ii) Fabrication other than welding shall be performed in accordance 
with American Institute of Steel Construction (AISC) publication, 
Specification for Structural Steel Buildings, Allowable Stress Design 
and Plastic Design, or other appropriate codes. The code to be followed 
during fabrication and construction shall be specified on design 
documents.
    (2) Welding. (i) Welding procedures and filler metals shall be 
selected to produce sound welds, and the filler metal shall have 
strength and toughness compatible with the base metal. Workmanship shall 
be in compliance with paragraph (b)(1)(i) of this section.
    (ii) Forming processes shall not degrade the base metals below their 
minimum required properties. A heat treatment shall be employed to 
provide the required properties, where necessary.
    (iii) Misalignment between parallel (abutting) members shall be 
minimized. Weld size for fillet welds shall be sufficient to compensate 
for the gap

[[Page 352]]

between faying surfaces of the members. Lapped joints shall possess 
sufficient overlaps. Both edges of an overlap joint shall have 
continuous fillet welds.
    (iv) When arc-air gouging is employed, the carbon buildup and 
burning of the weld or base metals shall be minimized.
    (v) Peening shall not be used for single-pass welds or for the root 
or cover passes of multipass welds. Peening shall be used only after 
cleaning of weld passes. Fairing by heating, flame shrinking, or other 
methods, when applied to Weld Class A or B structural elements, shall be 
performed without damaging the base metals. Such corrective measures 
shall be kept to a minimum when treating high-strength steels.
    (3) Quality assurance. A documented inspection plan shall be 
prepared and followed and shall cover the following items:
    (i) A suitable system for material identification and quality 
control during all stages of construction,
    (ii) Requirements for welding procedures and welder qualifications,
    (iii) The extent of weld inspection (including nondestructive 
examination methods) and the criteria for weld acceptance or rejection, 
and
    (iv) Necessary dimensional tolerances.
    (4) Weld nondestructive examination. (i) All welds shall be 
subjected to visual examination. Nondestructive examination shall be 
conducted to the extent indicated in paragraph (b)(4)(ii) of this 
section after all forming and postweld heat treatments have been 
completed. Weld examination procedures shall be adequate to detect 
delayed weld cracking in cases involving high-strength steels or high-
hydrogen welding processes.
    (ii) As called for in paragraph (b)(3)(iii) of this section, a plan 
for nondestructive examination of the welds shall be prepared and 
followed. The extent of inspection of Weld Classes A and B structural 
elements shall be consistent with the applications involved. Important 
welds of Weld Classes A and B structural elements are those inaccessible 
or very difficult to inspect in service. Important welds shall be 
subjected to an increased level of nondestructive examination during 
fabrication.
    (iii) If the proportion of unacceptable welds becomes excessive, the 
frequency of nondestructive examination shall be increased.
    (c) Design and analysis--(1) General. (i) Steel platforms shall be 
adequately designed and analyzed to withstand the loads to which they 
are likely to be exposed during their design life. The effects on the 
platform shall be determined for a minimum set of loading conditions by 
using a defensible method to ensure that the resulting responses do not 
exceed the safety criteria appropriate to the methods employed.
    (ii) The use of design methods, other than those specifically 
covered in this section, and their associated safety criteria are 
allowed if it can be demonstrated that such alternative methods will 
result in a structural safety level equivalent to that provided by the 
direct application of these requirements.
    (iii) Sections 250.905 and 250.906 of this part shall be consulted 
regarding definitions and requirements pertinent to the determination of 
loads and general design requirements.
    (2) Loading conditions. (i) Appropriate loading conditions that 
produce the most adverse effects on the platform during and after 
fabrication and installation shall be considered;
    (ii) Loadings corresponding to conditions after installation shall 
include at least those relating to both the operating and design 
environmental conditions, combined with other pertinent loads in the 
following manner:
    (A) Operating environmental conditions combined with dead and live 
loads appropriate to the function and operation of the platform;
    (B) Design environmental conditions combined with dead and live 
loads appropriate to the function and operation of the platform;
    (C) Design environmental conditions combined with dead loads and 
minimum live loads appropriate to the function and operation of the 
platform; and
    (iii) For platforms located in seismically active areas, loads 
induced by

[[Page 353]]

earthquake ground motions shall be combined with dead and live loads 
appropriate to the operation and function of the platform.
    (3) Methods of design and analysis. (i) The nature of loads and 
loading combinations as well as the local environmental conditions shall 
be considered in the selection of design methods. Methods of analysis 
and their associated assumptions shall be compatible with the overall 
design principles.
    (ii) Linear, elastic methods (working stress methods) of design and 
analysis are acceptable if proper measures are taken to prevent general 
and local buckling failure. Regarding structural instability as a 
possible mode of failure, the effects of initial stresses and geometric 
imperfection shall be taken into account.
    (iii) Dynamic effects shall be accounted for if the wave energy in 
the frequency range of the structural resonance frequencies is of 
sufficient magnitude to produce significant stresses in the platform. 
The determination of dynamic effects shall be accomplished either by 
computing the dynamic amplification effects in conjunction with a 
deterministic analysis or by a random dynamic analysis based on a 
spectral formulation. In the latter case, the analysis shall be 
accompanied by a statistical description and evaluation of the relevant 
input parameters.
    (iv) The interaction of the soil with the platform's piles shall be 
included in the analytical model used to obtain the structural response 
(see Sec. 250.909(d)(1)(ii) of this part).
    (v) For static loads, plastic methods of design and analysis shall 
be employed only when the properties of the steel and the connections 
exclude the possibility of brittle fracture and allow for formation of 
plastic hinges with sufficient plastic rotation capacity and adequate 
fatigue resistance.
    (vi) Whenever plastic analysis is used, it shall be demonstrated 
that the collapse mode (mechanism) corresponding to the smallest loading 
intensities has been used for the determination of the ultimate strength 
of the platform. The effect of buckling and other destabilizing 
nonlinear effects shall be taken into account in the plastic analysis of 
platforms with compressive forces. Whenever nonmonotonic or repeating 
loads are present, it shall be demonstrated that the structure will not 
fail by incremental collapse or fatigue.
    (vii) Under dynamic loads when plastic strains may occur, the 
considerations specified in paragraph (c)(3)(v) of this section shall be 
satisfied and any buckling and destabilizing nonlinear effects shall be 
taken into account.
    (4) Allowable stresses and load factors. (i) When the design is 
based on a working-stress method (see paragraphs (c)(1)(ii) and 
(c)(3)(ii) of this section), the safety criteria shall be expressed in 
terms of appropriate basic allowable stresses in accordance with 
requirements specified in paragraphs (c)(4) (ii) through (vi) of this 
section.
    (ii) For structural members and loadings covered by AISC 
publication, Specification for Structural Steel Buildings, Allowable 
Stress Design and Plastic Design, with the exception of earthquake 
loadings (see paragraph (c)(4)(v) of this section) and tubular 
structural members under the combined loading of axial compression and 
bending, the basic allowable stresses of the members shall be obtained 
using the AISC specification. For tubular members subjected to the 
aforementioned interaction, stress limits shall be set in accordance 
with a defensible formulation.
    (iii) Where stresses in members listed in paragraph (c)(4)(ii) of 
this section are shown to result from forces imposed by the design 
environmental conditions acting alone or in combination with dead and 
live loads (see paragraph (c)(2)(ii) of this section), the basic 
allowable stresses cited in paragraph (c)(4)(ii) of this section, 
modified by a factor of four-thirds, are permitted for the design 
environmental load contribution if the resulting structural member sizes 
are not less than those required for dead and live loads plus operating 
environmental conditions without the one-third increase in allowable 
stresses.
    (iv) For any two- or three-dimensional stress fields within the 
scope of the working-stress formulation, the equivalent stress (e.g., 
the von Mises stress intensity) shall be limited by an

[[Page 354]]

appropriate allowable stress less than the yield stress, with the 
exception of stresses of a highly localized nature. In the latter case, 
local yielding of the structure is acceptable if it can be demonstrated 
that such yielding does not lead to progressive collapse of the overall 
platform and that the general structural stability can be maintained.
    (v) When considering loading combinations on individual members or 
on the overall platform, which include loads defined as accidental (see 
Sec. 250.905(c)(4) of this part), or in pursuing structural analysis for 
earthquake loads (see paragraph (c)(2)(iii) of this section), the 
allowable stress set at a level of the minimum yield or buckling 
strength of the material shall be considered appropriate.
    (vi) Whenever elastic instability, overall or local, may occur 
before the compressive stresses reach the minimum specified yield 
strength of the material, appropriate allowable buckling stresses shall 
govern.
    (vii) Whenever the ultimate strength of the platform is used as the 
basis for the design of its members, the safety factors or the factored 
loads shall be formulated in accordance with the requirements of AISC 
publication, Specification for Structural Steel Buildings, Allowable 
Stress Design and Plastic Design, or an equivalent code. The capability 
of the primary structural members to develop their predicted ultimate 
load capacity shall be demonstrated.
    (viii) For details of high-stress concentration, consideration shall 
be given to safety against brittle fracture and to material quailty-
control procedures.
    (5) Structural response to earthquake loads. (i) Platforms located 
in seismically active areas shall be designed to possess adequate 
strength and stiffness to withstand the effects of an earthquake which 
has a reasonable likelihood of not being exceeded during the lifetime of 
the structure (see paragraph (c)(2)(iii) of this section) and remain 
stable during rare motions of greater severity;
    (ii) The adequacy of structural strength shall be demonstrated by 
analysis to verify that no significant structural damage occurs; and
    (iii) Platforms shall also possess adequate ductility to withstand a 
rare intense earthquake.
    (6) Fatigue assessment. (i) Structural members and joints for which 
fatigue is a probable mode of failure and for which past experiences are 
insufficient to ensure safety from possible cumulative fatigue damage 
shall be analyzed. Emphasis shall be given to joints and members in the 
splash zone, those that are difficult to inspect and repair after the 
platform is in service, and those susceptible to corrosion-accelerated 
fatigue, and
    (ii) For structural members and joints which require a detailed 
analysis of cumulative fatigue damage, the results of the analysis shall 
indicate a minimum calculated life of twice the design life (see 
Sec. 250.906(c)(1) of this part) of the platform if there is sufficient 
structural redundancy to prevent catastrophic failure of the platform as 
a result of fatigue failure of the member or joint under consideration. 
If such redundancy does not exist or if the desirable degree of 
redundancy is significantly reduced as a result of fatigue damages, the 
results of a fatigue analysis shall indicate a minimum calculated life 
of three times the design life of the platform.
    (d) Corrosion protection. All materials shall be protected from the 
effects of corrosion by a corrosion-protection system. The design of 
such systems shall take into account the possible existence of stress 
corrosion, corrosion fatigue, and galvanic corrosion. If the intended 
sea environment contains unusual contaminants, any special corrosive 
effects of such contaminants shall also be considered. Protection 
systems shall be designed in accordance with the National Association of 
Corrosion Engineers (NACE) publication, NACE Standard RP-01-76, 
Recommended Practice, Corrosion Control of Steel, Fixed Offshore 
Platforms Associated With Petroleum Production, or other comparable 
standards.
    (e) Connection of piles to structure. The attachment of the jacket 
structure to the piles shall be accomplished by positive, controlled 
means. Such attachments shall be capable of withstanding

[[Page 355]]

the static and long-term cyclic loadings to which they will be 
subjected.

[53 FR 10690, Apr. 1, 1988; 53 FR 26067, July 11, 1988, as amended at 61 
FR 60025, Nov. 26, 1996. Redesignated and amended at 63 FR 29479, 29486, 
May 29, 1998]



Sec. 250.908  Concrete-gravity platforms.

    (a) General. (1) This section covers the materials, analysis, 
design, and construction of reinforced and/or prestressed concrete-
gravity platforms.
    (2) Materials, structural systems, methods of design, and methods of 
construction that do not conform to the requirements of this section 
shall not be used unless it is shown that they will result in a safety 
level at least equivalent to that provided by the direct application of 
the requirements of this section.
    (b) Materials--(1) General. All materials shall be selected with due 
attention to their strength and durability in the marine environment. 
All material tests shall be performed in accordance with the latest, 
applicable standards of the American Society for Testing and Materials 
(ASTM).
    (2) Cement. (i) Cement must be equivalent to Type I, II, or III 
portland cement as specified by ASTM Standard C 150-99, Standard 
Specification for Portland Cement, or portland-pozzolan cement as 
specified by ASTM Standard C 595-98, Standard Specification for Blended 
Hydraulic Cements. However, the suitability of Type III cement to serve 
its intended function must be demonstrated.
    (ii) The tricalcium aluminate content of the cement shall be such as 
to enhance the corrosion protection of reinforcing steel without 
impairing the durability of concrete.
    (iii) If oil storage is planned and the oil is expected to contain 
soluble sulfates in amounts that may impair the durability of concrete, 
the tricalcium content shall be reduced or a suitable coating employed 
to protect the concrete.
    (3) Water. (i) Water used in mixing concrete shall be clean and free 
from injurious amounts of oils, acids, alkalis, salts, organic 
materials, or other substances that may be deleterious to concrete or 
steel.
    (ii) If nonpotable water is used, the proportions of materials in 
the concrete shall be based on test concrete mixes using water from the 
same source. The strength of mortar test cubes made with nonpotable 
water shall not be significantly below the strength of similar cubes 
made with potable water.
    (iii) Water for reinforced or prestressed concrete or grout shall 
not contain chlorides and sulfates in amounts detrimental to the 
durability of the platform.
    (4) Aggregates. (i) Aggregates must conform to the requirements of 
ASTM Standard C 33-99a, Standard Specification for Concrete Aggregates. 
Lightweight aggregates conforming to ASTM Standard C 330-99, Standard 
Specification for Lightweight Aggregates for Structural Concrete, will 
only be permitted if they do not pose durability problems and where they 
are used according to the applicable provisions of the ACI publication, 
ACI Standard 318, Building Code Requirements for Reinforced Concrete, 
plus Commentary.
    (ii) Marine aggregates shall be washed with fresh water before use 
to remove the surface and soluble chlorides and sulfates so that the 
total chloride and sulfate content of the concrete mix water does not 
exceed the limits of paragraph (b)(3)(iii) of this section.
    (iii) The maximum size of the aggregate shall be such that the 
concrete can be placed without voids.
    (5) Admixtures. The admixture shall be shown capable of maintaining 
essentially the same composition and performance throughout the work as 
the product used in establishing concrete proportions. Admixtures 
containing chloride ions shall not be used in prestressed concrete or in 
concrete containing aluminum embedments.
    (6) Reinforcing and prestressing systems. (i) Reinforcing and 
prestressing systems shall conform to the requirements of ACI 318; and
    (ii) Structural steel used in composite structures shall conform to 
the requirements of Sec. 250.907 of this part.
    (7) Concrete. The concrete shall be designed to ensure sufficient 
strength and durability. The quality control of

[[Page 356]]

concrete shall conform to ACI 318. The mixing, placing, and curing of 
concrete shall conform to the requirements of paragraph (e) of this 
section. The water-cement ratio shall be strictly controlled and in no 
case shall it exceed 0.45.
    (8) Grout for bonded tendons. (i) Grout for bonded tendons shall 
conform to ACI 318; and
    (ii) The maximum allowable contents of chlorides and sulfates 
determined in accordance with paragraph (b)(3)(iii) of this section 
shall also apply to grout mixes.
    (9) Post-tensioning ducts. Post-dentioning ducts shall conform to 
the requirements of ACI 318. Ducts and duct splices shall be watertight 
and grout-tight and shall be of suitable thickness to prevent crushing, 
deformation, and blockage.
    (10) Post-tensioning anchorages and couplers. Post-tensioning 
anchorages and couplers shall conform to the requirements of ACI 318.
    (c) Design requirements--(1) General. (i) The strength of the 
platform shall be adequate to resist failure of the platform or its 
components. Among the modes of possible failure that shall be considered 
are the following:
    (A) Loss of overall equilibrium,
    (B) Failure of critical sections, and
    (C) Instability (buckling).
    (ii) Additionally, the following items shall be considered in 
relation to their potential influences on the platform:
    (A) Cracking or spalling,
    (B) Deformations,
    (C) Corrosion of reinforcement or deterioration of concrete, and
    (D) Vibrations.
    (2) Required strength. The required strength shall conform to 
requirements of ACI 357R.
    (3) Design strength. The design strength shall conform to 
requirements of ACI 318 and ACI 357R.
    (4) Other design requirements. (i) In considering those items listed 
in paragraph (c)(1)(ii) of this section, the ability of the platform to 
withstand unfactored loads in the following combination shall be 
demonstrated:

D+T+L+E0


where L represents the most unfavorable live load; D, the dead load; T, 
the deformation load; and Eo, the operating environmental 
load, and
    (ii) Crack control design shall be achieved by limiting the crack 
width in concrete subjected to tension or by limiting the tensile stress 
in reinforcing steel and prestressing tendons.
    (5) Durability. (i) Materials, design, construction procedures, and 
quality control shall be such as to produce satisfactory durability of 
platforms in a marine environment, and
    (ii) The following items shall be considered in the four zones of 
exposure (see Sec. 250.906(c)(5) of this part):
    (A) Submerged zone--chemical deterioration of the concrete, 
corrosion of the reinforcement and hardware, and abrasion of the 
concrete;
    (B) Splash zone--freeze-thaw durability, corrosion of the 
reinforcement and hardware, the chemical deterioration of the concrete, 
and fire hazards;
    (C) Atmospheric zone--freeze-thaw durability, corrosion of 
reinforcement and hardware, and fire hazards; and
    (D) Ice zone--mechanical deterioration resulting from the abrasive 
action of moving ice.
    (6) Fatigue. Platforms for which fatigue is a probable mode of 
failure shall be designed to limit the effects of cumulative material 
fatigue. The effects of fatigue induced by normal stress and those 
resulting from shear and bond stress shall be considered. Particular 
attention shall be given to submerged areas subjected to the low-cycle, 
high-stress components of the anticipated loading history. If an 
analysis of the fatigue life is performed in lieu of employing other 
methods to obviate the possibility of fatigue damage, the calculated 
fatigue life of the platform shall be at least twice the design life 
(see Sec. 250.906(c)(1) of this part).
    (d) Analysis and design--(1) General. (i) The analysis of platforms 
shall be pursued under the assumptions of linearly elastic materials and 
linearly elastic structural behavior, except as listed in paragraphs 
(d)(1) (ii) and (iii) of this section.
    (ii) The inelastic behavior of concrete, based on the true variation 
of the modulus of elasticity with stress, shall be taken into account 
whenever its effect reduces the strength of the platform.

[[Page 357]]

    (iii) The geometric nonlinearities and the effect of initial 
deviation of the platform from the design geometry shall be taken into 
account whenever their effects reduce the strength of the platform.
    (iv) Where appropriate, dynamic effects shall be taken into account. 
The dynamic response shall be determined by a defensible method that 
includes the effects of the foundation--platform interaction and the 
effective mass of the surrounding water.
    (v) The material properties used in the analysis shall be based on 
actual laboratory tests or shall follow the appropriate sections of ACI 
318.
    (2) Analysis of frames. The analysis of frames shall be performed by 
a defensible method of structural mechanics. The buckling strength of 
the frame shall be assessed, and the safety against buckling failure 
shall be ensured to a degree consistent with the requirements in 
paragraphs (c)(2) and (c)(3) of this section.
    (3) Analysis of plates, shells, and folded plates. The buckling 
strength of these plates shall be determined and a sufficient safety 
margin against instability shall be ensured.
    (4) Determination of deflections. Deflections shall be determined by 
a defensible method. In addition to the immediate (instantaneous) 
deflections, the long-term deflections due to creep shall be accounted 
for.
    (5) Analysis and design for bending and axial loads. The provisions 
of ACI 318 shall apply to the analysis and design of members subject to 
flexure or axial loads or to combined flexure and axial loads.
    (6) Analysis and design for shear and torsion. The provisions of ACI 
318 shall apply to the analysis and design of members subject to shear 
or torsion or to combined shear and torsion.
    (7) Analysis and design of prestressed concrete. The analysis and 
design of prestressed concrete members and structures shall comply with 
ACI 318. In addition, the safety requirements of paragraph (c) of this 
section shall be satisfied.
    (8) Details of reinforcement and prestressing systems. Details of 
reinforcement and prestressing systems shall conform to the requirements 
of ACI 318 with special attention given to the fatigue resistance and 
ultimate behavior of offshore structures.
    (9) Minimum reinforcement. The minimum amount of reinforcement shall 
conform to the requirements of ACI 318. Additionally, sufficient 
reinforcement shall be provided to control crack growth, especially at 
surfaces exposed to severe hydraulic pressures.
    (10) Concrete cover of reinforcement and prestressing tendons. The 
concrete cover of reinforcement and prestressing tendons shall be 
sufficient to provide for corrosion protection of the steel.
    (11) Seismic analysis. A dynamic analysis shall be performed to 
determine the response of the platform to design-earthquake loading. The 
platform shall be designed to withstand this loading without damage. In 
addition, a ductility check shall also be performed to ensure that the 
platform has sufficient ductility to experience deflections more severe 
than those resulting from the design-earthquake loading without the 
collapse of the platform or its foundation or any primary structural 
component.
    (12) Seismic design. The design of structural members and details of 
platforms subjected to seismic loading shall ensure maximum ductility at 
critically loaded sections.
    (e) Construction--(1) General. (i) Construction methods and 
workmanship shall conform to the provisions of ACI 318 and to the 
following requirements.
    (ii) At each stage of construction, i.e., fabrication, initial 
flotation, towing, and installation in situ, the forces acting on the 
platform shall be kept within the safety limits listed in paragraph (c) 
of this section. Appropriate static and/or dynamic analysis shall be 
performed for the operating loading conditions of each of the 
construction operations mentioned above. Buoyancy and stability shall be 
considered during all phases of construction.
    (2) Mixing, placing, and curing of concrete. (i) Mixing of concrete 
must conform to the requirements of ACI Standard 318 and ASTM Standard C 
94/C 94M-99, Standard Specification for Ready-Mixed Concrete;
    (ii) When concreting in cold weather, the temperature of the fresh 
concrete shall be maintained sufficiently above

[[Page 358]]

freezing until the process of hardening is well in progress;
    (iii) In hot weather, the temperature of the fresh concrete shall be 
controlled so that it does not impair attainment of the desired strength 
and durability;
    (iv) The methods for curing concrete shall ensure maximum 
compressive and tensile strength, durability, and a minimum of cracking; 
and
    (v) The location and workmanship of construction joints shall not 
impair the strength, crack resistance, and watertightness of the 
platform.
    (3) Reinforcement. (i) Reinforcement shall be free from loose rust, 
grease, oil, deposits of salt, or any other material that may adversely 
affect the strength, durability, or bond of the reinforcement. The 
specified cover of reinforcement shall be maintained accurately. The 
cutting, bending, and fixing of reinforcement shall ensure that it is 
correctly positioned and rigidly held.
    (ii) The welding of reinforcement shall conform to the requirements 
of AWS publication, AWS D1.4, Structural Welding Code-- Reinforcing 
Steel.
    (4) Prestressing tendons, ducts, and grouting. (i) Steps shall be 
taken to ensure that the achieved prestressing force is that specified 
in the design.
    (ii) Tendons and ducts shall be in a condition that ensures the 
required strength, durability, and bond.
    (iii) The grouting procedures shall produce the required bond 
strength of the tendons and provide permanent corrosion protection for 
the tendons. Anchorages shall also be protected adequately against 
corrosion.

[53 FR 10690, Apr. 1, 1988, as amended at 61 FR 60025, Nov. 26, 1996. 
Redesignated and amended at 63 FR 29479, 29486, May 29, 1998; 65 FR 
15864, Mar. 24, 2000]



Sec. 250.909  Foundation.

    (a) General--(1) Coverage. Soil investigations, design 
considerations for the supporting soil, and the influence of the soil on 
the foundation structure are addressed in this section, including 
criteria for the strength and deformation characteristics of the 
foundation employed by both pile founded and gravity platforms.
    (2) Guidelines. (i) The degree of design conservatism shall reflect 
prior experience under similar conditions, the manner and extent of data 
collection, the scatter of design data, and the consequences of failure;
    (ii) For cases where the limits of applicability of any method of 
calculation employed are not well defined or where the soil 
characteristics are quite variable, the use of more than one method of 
calculation or a parametric study of the sensitivity of the important 
design variables shall be considered, and
    (iii) A listing of design parameters, necessary calculations, and 
test results shall be retained by the designer.
    (b) Site investigation--(1) General. (i) The actual extent, depth, 
and degree of precision to be obtained in the site investigation program 
shall reflect the type and intended use of the platform, characteristics 
of the site, similarity of the area based on previous site studies or 
platform installations as well as the consequences of a failure of the 
foundation. The site investigation program shall generally consist of 
three major phases as follows:
    (A) Shallow hazards (see paragraph (b)(2) of this section) to obtain 
relevant geophysical data.
    (B) Geological survey (see paragraph (b)(3) of this section) to 
obtain data of a regional nature concerning the site.
    (C) Subsurface investigation and testing (see paragraph (b)(4) of 
this section) to obtain the necessary geotechnical data. The results of 
these investigations shall be the basis for the additional site related 
studies specified in paragraph (b)(5) of this section.
    (ii) A complete site-investigation program shall be furnished for 
each platform. The positioning devices used on the vessel employed in 
the site investigation as well as those used during the installation of 
the platform shall have sufficient accuracy to ensure that the data 
obtained are pertinent to the actual final location of the platform.
    (2) Shallow hazard survey. (i) Consistent with the objectives of 
paragraph (b)(1)(i) of this section, a high-resolution or acoustic-
profiling survey shall be performed to obtain information on the 
conditions existing at and near the surface of the seafloor; and

[[Page 359]]

    (ii) The information to be obtained from this survey shall include 
the following items, as appropriate, for the planned platform:
    (A) Contours of the sea bed,
    (B) Presence of any seafloor surface or near-surface anomaly or 
obstructions which would adversely affect platform installation at the 
site,
    (C) Shallow faults,
    (D) Gas seeps,
    (E) Slump blocks,
    (F) Occurrence of shallow gas, and
    (G) Ice scour of seafloor sediments.
    (3) Geological survey. (i) Background geological data shall be 
obtained to provide regional information that can affect the design and 
siting of the platform. The data shall be considered in planning the 
subsurface investigation.
    (ii) Where necessary, the seismic activity at the site shall be 
assessed. Fault zones, the extent and geometry of faulting, and 
attenuation effects of conditions in the vicinity of the site shall be 
identified.
    (iii) For platforms located in a producing area, the possibility of 
seafloor subsidence shall be considered.
    (4) Subsurface investigation and testing. (i) The primary objective 
of the subsurface investigation and testing program shall be the 
attainment of reliable geotechnical data concerning the stratigraphic 
and engineering properties of the soil. These data shall be used to 
properly design the foundation to the desired structural safety level.
    (ii) The subsurface investigation and soil testing program shall 
consist of adequate in situ testing, boring, and sampling to examine all 
important soil and rock strata. The testing program shall reveal the 
necessary strength, classification, and deformation properties of the 
soil. Further tests, as needed, shall describe the dynamic 
characteristics of the soil.
    (iii) At least one borehole having a minimum depth of the 
anticipated length of the pile plus a zone of influence shall be drilled 
at the installation site for a pile-supported platform. Previously 
gathered borehole data may be used on a case-by-case basis, when 
approved by the Regional Supervisor. The zone of influence shall be 
sufficient to ensure that punch through failures will not occur. 
Additional boreholes of a lesser depth shall be required by the Regional 
Supervisor if discontinuities in the soil are indicated to exist in the 
area of the platform.
    (iv) For a gravity-type platform foundation, the required depth of 
the borehole shall be equal to at least the depth of the zone of 
influence which the structure imposes on the supporting soil. Where 
possible, in situ tests shall be performed to a depth that will include 
the anticipated shearing failure zone.
    (v) When samples from the field are sent to a laboratory for further 
testing, they shall be packed carefully and accurately labeled, and the 
results of visual inspections shall be recorded.
    (vi) A summary report showing the results of the soil testing 
program shall be prepared. The report shall describe briefly the various 
field and laboratory test methods employed and shall indicate the 
applicability of these methods as they relate to the quality of the 
sample, the type of soil, and the anticipated design application.
    (vii) The engineering properties of the soil to be used in the 
design shall be listed for each stratum. The selected design properties 
shall specify the uncertainties inherent in the overall testing program 
and in the reliability and applicability of the individual test methods.
    (5) Additional requirements. Based on the results of the overall 
site investigation program, studies shall be performed, as applicable, 
to assess the following effects of the installed platform:
    (i) Scouring potential of the seafloor,
    (ii) Hydraulic instability and the occurrence of sand waves,
    (iii) Instability of slopes in the area where the platform is to be 
placed,
    (iv) Liquefaction and/or possible reduction of soil strength due to 
increased pore pressures, and
    (v) Degradation of subsea permafrost layers.
    (c) Foundation design requirements--(1) General. (i) The loadings 
used in the design of the foundation shall include those defined in 
paragraph (c)(6)(ii) of this section.
    (ii) Foundation displacements shall be evaluated to ensure that they 
are

[[Page 360]]

within limits that do not impair the intended function and safety of the 
platform.
    (iii) The soil and the platform shall be considered as an 
interactive system, and the results of the analysis as required in 
paragraphs (c)(2) through (c)(6) of this section shall be evaluated from 
this point of view.
    (2) Cyclic loading effects. Evaluation of the short-term and long-
term effects of cyclic loading with respect to changes in soil 
characteristics, whether caused by conditions during installation, 
seismic activity, or storms, shall be accomplished by using defensible 
methods.
    (3) Scour. (i) For unprotected foundations, the depth and lateral 
extent of scouring, as determined in the site investigation program, 
shall be accounted for in design; and
    (ii) If scour is not accounted for in design, either effective 
protection shall be furnished soon after the installation of the 
platform or frequent visual inspection shall be carried out, 
particularly after major storms.
    (4) Settlements and displacements. (i) Based on the type and 
function of the platform, tolerable limits shall be established for 
settlements and lateral deflections. Due consideration shall be given to 
the effect of these movements on risers, pilings, and other components 
which interact with the platform;
    (ii) Maximum allowable values of platform movements, as limited by 
these structural considerations or overall platform stability, shall be 
considered in the design.
    (5) Dynamic considerations. (i) For dynamic-loading conditions, a 
defensible method shall be employed to simulate the interactive effects 
between the soil and the platform, and
    (ii) The evaluation of the dynamic response of the platform shall 
account for, as appropriate, the nonlinear and inelastic characteristics 
of the soil, the possible deterioration of strength, the increased or 
decreased damping due to cyclic soil loading, and the influence of 
nearby platforms.
    (6) Loading conditions. (i) Loadings producing the worst effects on 
the foundation during and after installation shall be addressed; and
    (ii) In-place platform loadings to be checked shall include at least 
those relating to both the operating and design environmental 
conditions, combined in accordance with the following:
    (A) Operating environmental conditions with dead and live loads 
appropriate to the function and operation of the platform,
    (B) Design environmental conditions with dead and live loads 
appropriate to the function and operation of the platform, and
    (C) Design environmental conditions with dead and minimum live loads 
appropriate to the function and operation of the platform.
    (d) Pile foundations--(1) General. The following requirements apply 
to pile-founded platforms. Pertinent parts of these requirements dealing 
with steel design shall be consulted regarding the design of the steel 
piles.
    (i) In the design of individual piles and piles in a group, the 
effects of axial, bending, and lateral loads shall be addressed.
    (ii) The design of a pile shall reflect the interactive behavior 
between the soil and the pile, between the pile and the platform, and 
between piles in a group.
    (iii) Methods of pile installation shall be consistent with the type 
of soil at the site and the installation equipment available. If 
unexpectedly high-driving resistance or other conditions lead to a 
failure of the pile to reach the desired penetration, the pile's 
capacities shall be reevaluated by considering the actual installation 
situation.
    (iv) Pile driving shall be performed and supervised by qualified and 
experienced personnel. Driving records which include such information as 
blowcounts and estimated hammer performance and stoppages shall be 
retained.
    (v) Where necessary, the effects of bottom instability in the 
vicinity of the platform shall be assessed.
    (2) Axial piles. (i) For piles in compression, the axial capacity 
shall be considered to consist of the skin friction, Qf, 
developed along the length of the pile and the end bearing, 
Qp, at the tip of the pile. The various parameters needed to 
evaluate Qf and Qp shall be

[[Page 361]]

predicted by using a defensible analytical method that employs reliably 
obtained soil data consistent with the prediction method selected. The 
acceptability of any method used to predict the components of pile 
resistance shall be demonstrated by showing satisfactory performance of 
the method under conditions similar to those existing at the actual 
site.
    (ii) The results of the dynamic pile driving analysis alone shall 
not be used to predict the axial load capacity of a pile.
    (iii) For piles driven through clay, the estimated skin friction 
developed over any increment of the pile surface shall not exceed the 
shear strength of the clay.
    (iv) The capacity of the internal plug of an open-ended pile shall 
be considered since it may limit the estimated end bearing to the pile.
    (v) When combining side friction and end-bearing effects in 
determining axial pile capacity, the load deflection response of the 
soil-pile system shall be addressed.
    (vi) For piles subjected to pullout loads, the contribution of the 
end resistance of the pile to its axial capacity shall not be 
considered. The possible variation of predicted pile-skin friction 
between the compressive and tensile modes of the axial-pile loading 
shall be considered.
    (3) Laterally loaded piles. (i) In evaluating the pile's behavior 
when acted upon by lateral loadings, the combined load deflection 
characteristics of the soil and the pile and the pile and the platform 
shall be addressed.
    (ii) The representation of the soil's lateral displacement when it 
is subjected to lateral loads shall adequately reflect the deterioration 
of the lateral load capacity when the soil is subjected to cyclic 
loading.
    (iii) The description of the lateral load versus displacement 
characteristics for the various soil strata shall be based on 
constitutive data obtained from suitable soil tests. The use of 
empirical methods to provide the description of the soil's lateral 
response shall be permitted if such methods are documented.
    (iv) Where applicable, the rapidly deteriorating cyclic lateral load 
capacity of stiff clays, especially those exhibiting the presence of a 
secondary structure, shall be addressed in the design.
    (v) Calculation of pile deflection and stress induced by lateral 
loads shall account for the nonlinear interaction between the soil and 
the pile.
    (4) Pile groups. Where applicable, the effects of close spacing on 
the load and deflection characteristics of pile groups shall be 
determined. The allowable load for a group, both axial and lateral, 
shall not exceed the sum of the apparent individual pile allowable 
loads.
    (5) Plastic analysis. When the design of a platform is based on the 
formation collapse mechanisms associated with a plastic analysis method, 
influence of the soil's support on the pile shall be addressed.
    (e) Gravity platforms foundations--(1) General. The following 
requirements apply to soil foundations for gravity platforms. Section 
250.138 of this part shall be consulted regarding the design of the base 
slab.
    (i) The influence of hydraulic and slope instability, if any, shall 
be determined for the structural loading cases that include the design 
environmental loading.
    (ii) The effects of adjacent platforms and the variation of soil 
properties in the horizontal direction shall be considered, as 
appropriate.
    (iii) The stability of the foundation with regard to bearing and 
sliding failure modes shall be investigated by employing the soil shear 
strengths determined with consideration of paragraphs (b)(4) and (c)(2) 
of this section.
    (iv) When an underpressure or overpressure is experienced by the 
seafloor under the platform, provisions shall be made to prevent piping 
that could impair the integrity of the foundation.
    (v) Initial, consolidation, and secondary settlements, as well as 
permanent horizontal displacements, shall be determined.
    (vi) If the intended site is not level, the predicted tilt of the 
overall platform shall be based on the average bottom slope of the 
seafloor and the tolerance of the measuring device used in the site-
investigation program. Differential settlement shall also be calculated 
and the tilting of the platform

[[Page 362]]

caused by this settlement shall be combined with the predicted 
structural tilt of the overall platform. Any increased loading effects 
caused by tilting of the platform shall be addressed in stability 
requirements specified for the foundation.
    (2) Stability. (i) The bearing capacity and lateral resistance shall 
be calculated by considering the most unfavorable combination of loads. 
The long-term redistribution of bearing pressures under the base slab 
shall be considered to ensure that the maximum edge pressures are used 
in the design of the base.
    (ii) The lateral resistance of the platform shall be investigated 
considering various potential shearing planes. The presence of any soft 
layers shall require special consideration.
    (iii) Calculations for overturning moment and vertical forces 
induced by the passage of a wave shall include the vertical pressure 
distribution across the top of the foundation and along the seafloor. 
The foundation shall not lose contact with the soil due to uplift 
created by the maximum overturning moment.
    (iv) The capacity of the foundation to resist a deep-seated bearing 
failure shall be analyzed.
    (v) Where present, the additional effects of penetrating walls or 
skirts that transfer vertical and lateral loads to the soil shall be 
investigated for their contribution to bearing load capacity and lateral 
resistance.
    (3) Soil reaction on the platform. (i) For conditions during and 
after installation, the reaction of the soil against all structural 
members seated on or penetrating into the seafloor shall be determined 
and accounted for in the design of these members.
    (ii) The distribution of soil reactions shall be based on the 
results obtained in paragraphs (b)(2) and (b)(4) of this section, and 
the calculations of soil reactions shall account for any deviation from 
a plane surface, the load-deflection characteristics of the soil, and 
the geometry of the platform base.
    (iii) Where applicable, effects of local soil stiffening, 
nonhomogeneous soil properties, and boulders and other obstructions 
shall be addressed in the design. During installation, the possibility 
of local contact pressures due to irregular contact between the base and 
the seafloor shall be considered. Contact pressures shall be added to 
the hydrostatic pressure.
    (iv) The penetration resistance of structural elements projecting 
into the seafloor below the foundation structure shall be analyzed. The 
design of the ballasting system shall reflect uncertainties associated 
with achieving the required penetration of the platform.



Sec. 250.910  Marine operations.

    (a) General--(1) Marine operations means all activities necessary 
for the transportation and installation of a platform from the time it 
enters the marine environment until it is fixed in place at its final 
destination. Marine operations generally include such activities as 
follows:
    (i) Lifting and mooring,
    (ii) Loadout or initial flotation,
    (iii) Fabrication afloat,
    (iv) Towing,
    (v) Launching and uprighting,
    (vi) Submergence,
    (vii) Pile installation, and
    (viii) Final field erection.
    (2) The requirements of this section apply to all platforms covered 
by this subpart, regardless of structural type or material of 
construction.
    (b) Objective. The structural strength and integrity of a platform 
shall not be reduced or otherwise jeopardized by the performance of the 
activities required to install the platform on site. The type and 
magnitude of loads and load combinations to which a platform will be 
exposed during marine operations shall be the subject of an analysis 
pursuant to paragraph (c) of this section, except where the use of 
proven and well-controlled methods of fabrication and installation are 
proposed and justified. Sufficient equipment shall be provided to ensure 
installation of the platform in a safe and well-controlled manner.
    (c) Analysis. (1) Analyses shall be performed to determine the type 
and magnitude of the loads and load combinations to which the platform 
will be exposed during the performance of marine operations.

[[Page 363]]

    (2) Analyses shall be performed to ensure that the structural design 
is sufficient to withstand the type and magnitude of the loads and load 
combinations determined, in accordance with paragraph (c)(1) of this 
section, without loss or degradation of structural integrity.
    (3) Analyses shall be performed to ensure that the platform or its 
means of support has sufficient hydrostatic stability and reserve 
buoyancy to allow for successful execution of all phases of marine 
operations.



Sec. 250.911  Inspection during construction.

    (a) General--(1) Coverage. All pile-supported and gravity platforms 
covered by this subpart shall be inspected during the construction 
phase. Additional requirements for steel pile-supported platforms are 
contained in paragraph (b) of this section, and additional requirements 
pertaining to concrete-gravity platforms are contained in paragraph (c) 
of this section. The phases of construction subject to inspection 
include material manufacture, fabrication, loadout, transportation, 
positioning, installation, and final field erection.
    (2) Objective. Inspections during construction are to verify that 
the platform is constructed in accordance with the approved construction 
plan. Any unusual or innovative application of materials or methods of 
construction not adequately covered by the requirements of this section 
shall receive special attention during compliance inspections relevant 
to its effect on the integrity of the platform.
    (3) Remedial action. If construction inspection results reveal that 
materials, procedures, or workmanship deviate significantly from the 
approved design, remedial action shall be taken.
    (4) Identification of materials. The origin of materials used in the 
platform and the results of relevant material tests for all significant 
structural materials shall be retained and made readily available for 
inspection by MMS representatives during all stages of construction. 
Records shall be kept of the locations throughout the platform of the 
various heat numbers for such materials.
    (b) Steel pile-supported platforms--(1) Scope. Inspections of steel 
pile-supported platforms shall address the following topics, as 
appropriate:
    (i) Material quality and forming,
    (ii) Welder and welding procedure qualifications,
    (iii) Weld inspection,
    (iv) Tolerances and alignments, and
    (v) Corrosion-control systems.
    (2) Material quality and forming. Inspection shall verify that all 
materials employed are of good quality and suitable for their intended 
service as specified in the approved design. Inspection shall ensure the 
compliance of materials to the relevant material standards selected in 
the design of the platform. Inspection shall ensure that formed members 
satisfy the dimensional tolerances listed in the design.
    (3) Welder and welding-procedure qualifications. (i) Welders shall 
be tested and possess a current welder's certification.
    (ii) All welding procedures to be employed shall be tested and 
certified for the production of satisfactory welds. Welding procedures 
previously tested and certified shall be considered prequalified.
    (4) Weld inspection. (i) Inspection shall include, but not be 
limited to, visual inspection of all welds and representative magnetic 
particle or dye penetrant inspection of welds of Weld Classes A and B 
materials (see Sec. 250.907(a)(4) of this part) not subjected to 
ultrasonic or radiographic inspection. The extent of ultrasonic or 
radiographic inspection shall be specified and shall emphasize, but not 
be confined to, welds of Weld Class A materials.
    (ii) The extent and methods of inspection shall be consistent with 
the classification of applications (see Sec. 250.907(a)(4) of this part) 
of the area being examined.
    (iii) Any welding not meeting the acceptance criteria specified in 
the inspection plan shall be rejected and appropriate remedial action 
taken.
    (5) Tolerances and alignments. Overall dimensional tolerances, 
forming tolerances, and local alignment tolerances shall be commensurate 
with those considered in developing the structural design. Inspections 
shall ensure that the dimensional tolerance criteria are

[[Page 364]]

being met. Out of roundness of structural elements for which buckling is 
the anticipated mode of failure shall receive individual inspection.
    (6) Corrosion-control systems. Corrosion-control systems employed on 
the platform shall be inspected to ensure that they are installed as 
specified in the approved design. Inspection shall ensure that proper 
protection against galvanic effects, especially in locations where 
nonferrous materials are used in conjunction with steel, has been 
provided in the corrosion-control system.
    (7) Additional inspection items. (i) The provisions of paragraphs 
(b)(2) through (b)(6) of this section relate only to matters directly 
affecting the onshore construction phases of the platform. Other items 
relating to the onshore construction site and the construction phases 
from loadout to final erection shall also be performed.
    (ii) The construction site shall be inspected to ensure that 
adequate consideration has been given to the following items:
    (A) Support of the platform during construction,
    (B) Employment of a sufficient number of certified welders and 
inspectors to maintain an adequate quality of work, and
    (C) Weathertight storage of welding consumables under conditions 
specified by their manufacturers.
    (iii) Inspection shall verify that the following operations have 
been accomplished in a manner conforming to approved plans or drawings:
    (A) Loadout,
    (B) Tie down,
    (C) Positioning at the site,
    (D) Installation (see Sec. 250.909(d)(1)(iv) of this part for 
piles), and
    (E) Final field erection.
    (iv) To determine if overstressing of the platform during 
transportation has occurred, towing records shall be reviewed to 
ascertain if conditions during towing operations exceeded those employed 
in the analyses required by Sec. 250.910(c) of this part.
    (v) When the inspections indicate that overstressing has occurred 
during loadout, transportation, or installation, the affected parts of 
the platform shall be surveyed to determine the extent of actual damage, 
if any. Where necessary, a reevaluation of the structural capacity shall 
be carried out, considering the results of the survey.
    (8) Records. The following construction records shall be compiled, 
retained, and made available for inspection by MMS representatives:
    (i) Mill certificates,
    (ii) Weld-procedure qualification records,
    (iii) Weld inspection records,
    (iv) Dimensional tolerance reports,
    (v) Towing records, and
    (vi) Pile driving records.
    (c) Concrete-gravity platforms--(1) Scope. Inspection of concrete-
gravity platforms shall address the following topics, as appropriate:
    (i) Preparation for concrete production and placement;
    (ii) Batching, mixing, and placing concrete;
    (iii) Form removal and concrete curing;
    (iv) Pretensioning and grouting;
    (v) Joints; and
    (vi) Finished concrete.
    (2) Preparation for concrete production and placement. (i) 
Inspection shall ensure that the pertinent physical properties of 
cement, reinforcing steel, prestressing tendons, and appurtenances 
comply with those specified in the approved design.
    (ii) Forms and shoring supporting the forms shall be inspected to 
ensure that they are adequate in number and type and are located 
correctly.
    (iii) The dimensional tolerances of the forms shall be inspected to 
ensure that the finished dimensional tolerances are comparable to those 
allowed for in the approved design.
    (iv) Reinforcing steel, prestressing tendons, post-tensioning ducts, 
anchorages, and any other embedded steel shall be inspected, as 
appropriate, for size, bending, spacing, location, firmness of 
installation, surface condition, vent locations, proper duct coupling, 
and duct capping.
    (3) Batching, mixing, and placing concrete. (i) Inspections shall be 
performed to ensure that the procedures for the production and placement 
of concrete provide a well-mixed and well-compacted concrete. The 
procedures shall also limit segregation, loss of material,

[[Page 365]]

contamination, and premature initial set during all operations.
    (ii) Inspection shall verify that the mix components of each batch 
of concrete are properly proportioned and within allowable variations 
specified in the approved design. Inspection shall ensure that the 
water/cement ratio of each batch is within the limit specified in 
Sec. 250.908(b)(7) of this part.
    (iii) Aggregate gradation, cleanliness, moisture content, and unit 
weight shall be tested. The frequency of testing shall be determined 
taking into account the uniformity of the supply source, volume of 
concrete used, and variations of atmospheric conditions.
    (iv) Mix water shall be tested for purity following specified 
methods and schedules.
    (v) Testing during the production of concrete shall be performed to 
monitor, as a minimum, the following concrete qualities:
    (A) Consistency,
    (B) Air content, and
    (C) Strength.
    (4) Form removal and concrete curing. (i) Inspection shall ensure 
that forms and form supports are not removed until the platform has 
attained sufficient strength to bear its own weight, construction loads, 
and anticipated environmental loads without undue deformation and that 
they are removed according to schedule.
    (ii) Inspection shall ensure that curing of concrete is accomplished 
in accordance with the provisions of a predetermined procedure.
    (iii) Where the construction procedures require the submergence of 
recently placed concrete, inspection shall ensure that methods for 
protecting the concrete from the effects of salt water are properly 
executed.
    (5) Pretensioning and grouting. (i) Inspection shall verify that the 
sequence of tendon tensioning and the resulting elongation and force are 
in accordance with provisions specified in the approved design.
    (ii) Pretensioning or post-tensioning stress shall be determined by 
measuring both tendon elongation and tendon force. Inspection shall 
verify that the variation of measurements does not exceed a specified 
amount.
    (iii) Inspection shall verify that grout mix proportions and ambient 
conditions during mixing are in accordance with provisions designated in 
the approved design. Tests for grout, viscosity expansion, bleeding, 
compressive strength, and setting time shall be performed to ensure 
compliance with design requirements. Procedures shall be observed to 
ensure that ducts are completely filled.
    (iv) Anchorages shall be inspected to ensure that they are located 
and sized as specified in the design and are provided with adequate 
cover to mitigate the effects of corrosion.
    (6) Joints. Where appropriate, leak testing of construction joints 
shall be performed by using specified procedures. When deciding which 
joints to inspect, consideration shall be given to the hydrostatic head 
on the subject joint during normal operation, the consequence of a leak 
at the subject joint, and the ease of repair once the platform is in 
service.
    (7) Finished concrete. (i) The surface of the hardened concrete 
shall be completely inspected for cracks, honeycombing, popouts, 
spalling, and other surface imperfections.
    (ii) The platform shall be examined by using a calibrated rebound 
hammer or a similar nondestructive examination device. Inspection shall 
verify that the results of surface inspection, cylinder strength test, 
or nondestructive examination are in accordance with the approved design 
criteria.
    (iii) The completed sections of the platform shall be checked for 
compliance to specified design tolerances of thickness and alignment 
and, to the extent practicable, the location of reinforcing and 
prestressing steel and post-tensioning ducts.
    (8) Additional inspection items. (i) While the provisions of 
paragraphs (c)(2) through (c)(7) of this section relate only to some 
matters directly affecting the onshore or nearshore construction phases 
of the platform, other items relating to such phases and from loadout to 
final erection shall also be considered.
    (ii) Inspection shall ensure that adequate consideration has been 
given the following items:

[[Page 366]]

    (A) Support of the structure during construction,
    (B) Employment of a sufficient number of competent workmen and 
inspectors to maintain an adequate quality of work,
    (C) Storage of cement and prestressing tendons in weathertight 
areas,
    (D) Storage of admixtures and epoxies according to manufacturers' 
specifications, and
    (E) Storage of aggregates to limit segregation, contamination by 
deleterious substances, and moisture variations within the stockpile.
    (iii) Inspection shall verify that the following operations, as 
applicable to the planned platform, have been accomplished in a manner 
conforming to approved plans or drawings developed for these operations:
    (A) Loadout,
    (B) Towing arrangements,
    (C) Positioning at the site,
    (D) Installation, and
    (E) Final field erection.
    (iv) To determine if overstressing of the platform during 
transportation has occurred, towing records shall be reviewed to 
ascertain if conditions during the towing operations exceeded those 
employed in the analyses required by Sec. 250.910(c) of this part.
    (9) Records. The following construction records shall be compiled, 
retained, and made available for inspection by MMS representatives:
    (i) Material certificates and test reports;
    (ii) Tensioning and grouting records;
    (iii) Concreting records including weight, moisture content, mix 
proportions, test methods and results, ambient conditions during the 
pour, and test equipment calibration data;
    (iv) Deviations from design or fabrication specifications and 
repairs carried out;
    (v) Towing records; and
    (vi) Data on initial structural settlements.

[53 FR 10690, Apr. 1, 1988; 53 FR 26067, July 11, 1988. Redesignated and 
amended at 63 FR 29479, 29486, May 29, 1998; 64 FR 9065, Feb. 24, 1999]



Sec. 250.912  Periodic inspection and maintenance.

    (a) All platforms installed in the OCS shall be inspected 
periodically in accordance with the provisions of API RP 2A, section 14, 
Surveys. However, use of an inspection interval which exceeds 5 years 
shall require prior approval by the Regional Supervisor. Proper 
maintenance shall be performed to assure the structural integrity of the 
platform as a workbase for oil and gas operations.
    (b) A report shall be submitted annually on November 1 to the 
Regional Supervisor stating which platforms have been inspected in the 
preceding 12 months, the extent and area of inspection, and the type of 
inspection employed, i.e., visual, magnetic particle, ultrasonic 
testing. A summary of the testing results shall be submitted indicating 
what repairs, if any, were needed and the overall structural condition 
of the platform.

[53 FR 10690, Apr. 1, 1988, as amended at 55 FR 51415, Dec. 14, 1990. 
Redesignated at 63 FR 29479, May 29, 1998]



Sec. 250.913  Platform removal and location clearance.

    (a) The lessee shall remove all structures in a manner approved by 
the Regional Supervisor to assure that the location has been cleared of 
all obstructions to other activities in the area.
    (b) All platforms (including casing, wellhead equipment, templates, 
and piling) shall be removed by the lessee to a depth of at least 15 
feet below the ocean floor or to a depth approved by the Regional 
Supervisor based upon the type of structure or ocean-bottom conditions.
    (c) The lessee shall verify by appropriate means that the location 
has been cleared of all obstructions. The results of the location 
clearance survey shall be submitted to the Regional Supervisor by means 
of a letter from the company performing the work certifying that the 
area was cleared of all obstructions, the date the work was performed, 
the extent of the area surveyed, and the survey method used.

[[Page 367]]



Sec. 250.914  Records.

    The lessee shall compile, retain, and make available to Minerals 
Management Service representatives for the functional life of all 
platforms, the as-built structural drawings, the design assumptions and 
analyses, a summary of the nondestructive examination records, and the 
inspection results from platform inspections required by Sec. 250.912 of 
this part.

[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 
29486, May 29, 1998]



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



Sec. 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 shall be submitted to the Regional Supervisor and 
approval obtained prior to the installation, modification, or 
abandonment of a pipeline which qualifies as a lease term pipeline (see 
Sec. 250.1001, Definitions) and prior to the installation of a right-of-
way pipeline or the modification or relinquishment of a pipeline right-
of-way.
    (c)(1) Department of the Interior (DOI) pipelines, as defined in 
Sec. 250.1001, must meet the requirements in Secs. 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.
    (d) A pipeline which qualifies as a right-of-way pipeline (see 
Sec. 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-

[[Page 368]]

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]



Sec. 250.1001  Definitions.

    Terms used in this subpart shall have the meanings given below:
    DOI pipeline refers to a pipeline extending upstream from a point on 
the OCS where operating responsibility transfers from a producing 
operator to a transporting operator.
    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.
    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.)
    Right-of-way pipelines are those pipelines which--
    (a) Are contained within the boundaries of a single lease or group 
unitized leases but are not owned and operated by the lessee or operator 
of that lease or unit,
    (b) Are contained within the boundaries of contiguous (not 
cornering) leases which do not have a common lessee or operator,
    (c) 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
    (d) 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]



Sec. 250.1002  Design requirements for DOI pipelines.

    (a) The internal design pressure for steel pipe shall be determined 
in accordance with the following formula:
[GRAPHIC] [TIFF OMITTED] TC15NO91.019


For limitations see section 841.121 of American National Standards 
Institute (ANSI) B31.8 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. 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

[[Page 369]]

strength of the fitting shall at least be equal to the computed bursting 
strength of the pipe.
    (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) 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, redundant safety devices meeting the requirements of section A9 of 
API RP 14C shall be installed and maintained. 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.



Sec. 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 hydrostatically 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

[[Page 370]]

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]



Sec. 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 to 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 shall comply with Section A7 of API RP 14C. 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]



Sec. 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.

[[Page 371]]

    (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 measurements.



Sec. 250.1006  Abandonment and out-of-service requirements for DOI pipelines.

    (a)(1) A pipeline may be abandoned in place if, in the opinion of 
the Regional Supervisor, it does not constitute a hazard to navigation, 
commercial fishing operations, or unduly interfere with other uses in 
the OCS. Pipelines to be abandoned in place shall be flushed, filled 
with seawater, cut, and plugged with the ends buried at least 3 feet.
    (2) Pipelines abandoned by removal shall be pigged, unless the 
Regional Supervisor determines that such procedure is not practical, and 
flushed with water prior to removal.
    (b)(1) Pipelines taken out-of-service shall be blind flanged or 
isolated with a closed block valve at each end.
    (2) Pipelines taken out-of-service for a period of more than 1 year 
shall be flushed and filled with inhibited seawater.
    (3) Pipelines taken out-of-service shall be returned to service 
within 5 years or be abandoned in accordance with the requirements of 
paragraph (a) (1) or (2) of this section.



Sec. 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,

[[Page 372]]

    (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 shall include a description of any additional 
design precautions which were 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.
    (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.
    (c) Applications to abandon a lease term pipeline or relinquish a 
right-of-way grant shall be submitted in triplicate to the Regional 
Supervisor and shall include the following:
    (1) Reason for operation,
    (2) Proposed procedures,
    (3) ``As-built'' location plat,
    (4) Length in feet of segment to be abandoned or relinquished, and
    (5) Length in feet of segment remaining.

[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]



Sec. 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 shall notify the Regional 
Supervisor prior to the repair of any pipeline or as soon as 
practicable. A detailed report of the repair of a pipeline or pipeline 
component shall be submitted to the Regional Supervisor within 30 days 
after completion of the repairs. The report shall 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

[[Page 373]]

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 Sec. 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]



Sec. 250.1009  General requirements for a pipeline right-of-way grant.

    (a)(1) In addition to applicable requirements of Secs. 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.
    (2) 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.
    (b)(1) When you apply for, or are the holder of, a right-of-way, you 
must:
    (i) 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
    (ii) Provide additional security if the Regional Director determines 
that a bond in excess of $300,000 is needed.
    (2) For the purpose of this paragraph, there are three areas:
    (i) The areas offshore the Gulf of Mexico and Atlantic Coast;
    (ii) The area offshore the Pacific Coast States of California, 
Oregon, Washington, and Hawaii; and
    (iii) The area offshore the Coast of Alaska.
    (3) 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.
    (4) 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.
    (c) An applicant, by accepting a right-of-way grant, agrees to 
comply with the following requirements:
    (1) The right-of-way holder shall comply with applicable laws and 
regulations and the terms of the grant.
    (2) For the first calendar year, or fraction thereof, and annually 
thereafter, the right-of-way holder shall pay MMS, in advance, an annual 
rental of $15 for each statute mile, or fraction thereof, traversed by 
the right-of-way and $75 for each area to be used as a site for an 
accessory to the right-of-way pipeline including, but not limited to, a 
platform. Payments may be on an annual basis, for a 5-year period, or 
for multiples of 5 years.
    (3) 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-

[[Page 374]]

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.
    (4) 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 lessee how to protect it.
    (5) 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.
    (6) 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.
    (7)(i) 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.
    (ii) Unless otherwise exempted by FERC pursuant to 43 U.S.C. 
1334(f)(2), the holder shall--
    (A) Provide open and nondiscriminatory access to a right-of-way 
pipeline to both owner and nonowner shippers, and
    (B) 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.
    (8) 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.
    (9) 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 Sec. 250.1014 of this part.
    (d) 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.
    (e) 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

[[Page 375]]

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]



Sec. 250.1010  Applications for a pipeline right-of-way grant.

    (a) You must submit an original and three copies of an application 
for a new or modified pipeline right-of-way grant to the Regional 
Supervisor. The application must address those items required by 
Sec. 250.1007 (a) or (b) of this subpart, as applicable. It must also 
state the primary purpose for which you will use the right-of-way grant. 
If the right-of-way 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 Sec. 250.1009(c)(2) 
of this subpart and a non-refundable filing fee of $2,350 for a pipeline 
right-of-way grant to install a new pipeline or a non-refundable filing 
fee of $300 for a pipeline right-of-way grant to convert an existing 
lease term pipeline into a right-of-way pipe-
line. MMS periodically will amend the filing fee based on its experience 
with the costs for administering pipeline right-of-way applications. If 
the costs change by a percentage of not more than the percentage change 
in the CPI ``U'' since the last change to the filing fee, MMS will amend 
the application fee by the percentage of the change in costs without 
notice and opportunity for comment. If costs increase by a percentage 
more than the percentage change in the CPI ``U'' since the last change 
to the filing fee, MMS will provide notice and an opportunity to comment 
before it changes the filing fee. An application to modify an approved 
right-of-way grant shall be accompanied by the additional rental 
required under Sec. 250.1009(c)(2), if applicable. A separate 
application shall be filed for each right-of-way.
    (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.

[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]



Sec. 250.1011  Granting a pipeline right-of-way.

    (a) In considering an application for a right-of-way, the Regional 
Supervisor

[[Page 376]]

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 Sec. 250.1010(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]



Sec. 250.1012  Requirements for construction under a right-of-way grant.

    (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

[[Page 377]]

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.



Sec. 250.1013  Assignment of a right-of-way grant.

    (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 shall be 
accompanied by the same showing of qualifications of the assignees as is 
required of an applicant for a right-of-way in Sec. 250.1010 of this 
subpart and shall be supported by a statement that the assignee agrees 
to comply with and to be bound by the terms and conditions of the right-
of-way grant. The assignee shall satisfy the bonding requirements in 
Sec. 250.1009(b) of this part. No transfer shall be recognized unless 
and until it is first approved, in writing, by the Regional Supervisor. 
A nonrefundable filing fee of $60 must accompany the application for the 
approval of an assignment. MMS periodically will amend the filing fee 
based on its experience with the costs for administering pipeline right-
of-way assignment applications. If the costs increase by more than the 
CPI ``U,'' MMS will provide notice and opportunity for comment before 
changing the filing fee. For lesser cost increases or cost reductions 
MMS will change the fee without such procedures.

[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]



Sec. 250.1014  Relinquishment of a right-of-way grant.

    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 shall contain those items addressed in 
Sec. 250.1007(c) 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 Sec. 250.1009(c)(9) of this part.

[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 
29486, May 29, 1998]



                 Subpart K--Oil and Gas Production Rates



Sec. 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

[[Page 378]]

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.



Sec. 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 
Sec. 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.

[53 FR 10690, Apr. 1, 1988. Redesignated and amended at 63 FR 29479, 
29486, May 29, 1998]



Sec. 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, Request for Reservoir 
Maximum Efficient Rate (MER), 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

[[Page 379]]

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 Sec. 250.190.
    (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 Sec. 250.190.
    (9) Public information copies of Form MMS-128 shall be submitted in 
accordance with Sec. 250.190.
    (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

[[Page 380]]

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]



Sec. 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) (15.025 psia 
in the Gulf of Mexico OCS Region) and 60  deg. 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.



Sec. 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.



Sec. 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

[[Page 381]]

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 
H2S--(1) Flaring of gas containing H2S. (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 (Sec. 250.417(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 Secs. 250.303 
and 250.304.
    (2) Venting of gas containing H2S. 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 H2S. 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]



Sec. 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.

[[Page 382]]

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.



Sec. 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.



Sec. 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           Sec.  250.1202(a)
 measuring liquid hydrocarbons?.
 2. What are the requirements for liquid    Sec.  250.1202(b)
 hydrocarbon royalty meters?.
 3. What are the requirements for run       Sec.  250.1202(c)
 tickets?.
 4. What are the requirements for liquid    Sec.  250.1202(d)
 hydrocarbon royalty meter provings?.
 5. What are the requirements for           Sec.  250.1202(e)
 calibrating a master meter used in
 royalty meter provings?.
 6. What are the requirements for           Sec.  250.1202(f)
 calibrating mechanical-displacement
 provers and tank provers?.
 7. What correction factors must a lessee   Sec.  250.1202(g)
 use when proving meters with a mechanical
 displacement prover, tank prover, or
 master meter?.
 8. What are the requirements for           Sec.  250.1202(h)
 establishing and applying operating meter
 factors for liquid hydrocarbons?.
 9. Under what circumstances does a liquid  Sec.  250.1202(i)
 hydrocarbon royalty meter need to be
 taken out of service, and what must a
 lessee do?.
10. How must a lessee correct gross liquid  Sec.  250.1202(j)
 hydrocarbon volumes to standard
 conditions?.
11. What are the requirements for liquid    Sec.  250.1202(k)
 hydrocarbon allocation meters?.
12. What are the requirements for royalty   Sec.  250.1202(l)
 and inventory tank facilities?.
13. To which meters do MMS requirements     Sec.  250.1203(a)
 for gas measurement apply?.
14. What are the requirements for           Sec.  250.1203(b)
 measuring gas?.
15. What are the requirements for gas       Sec.  250.1203(c)
 meter calibrations?.
16. What must a lessee do if a gas meter    Sec.  250.1203(d)
 is out of calibration or malfunctioning?.
17. What are the requirements when natural  Sec.  250.1203(e)
 gas from a Federal lease is transferred
 to a gas plant before royalty
 determination?.
18. What are the requirements for           Sec.  250.1203(f)
 measuring gas lost or used on a lease?.
19. What are the requirements for the       Sec.  250.1204(a)
 surface commingling of production?.
20. What are the requirements for a         Sec.  250.1204(b)
 periodic well test used for allocation?.
21. What are the requirements for site      Sec.  250.1205(a)
 security?.
22. What are the requirements for using     Sec.  250.1205(b)
 seals?.
------------------------------------------------------------------------


[63 FR 26370, May 12, 1998. Redesignated and amended at 63 FR 29479, 
29487, May 29, 1998]



Sec. 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

[[Page 383]]

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 
deg.F) to 60.5 degrees Fahrenheit (60.5  deg.F) at standard pressure 
base (14.73 pounds per square inch absolute (psia)).
    Calibration--testing (verifying) and correcting, if necessary, a 
measuring device to industry accepted, manufacturer's recommended, or 
regulatory required standard of accuracy.
    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  deg.F.
    Surface commingling--the surface mixing of production from two or 
more leases or units prior to measurement for royalty purposes.

[[Page 384]]

    Temperature base--the temperature at which gas and liquid 
hydrocarbon volumes and quality are reported. The standard temperature 
base is 60  deg.F.
    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]



Sec. 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 changes to previously approved measurement 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.

[[Page 385]]

    (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 250.101; 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

[[Page 386]]

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 allocation meters monthly if they measure 50 or more 
barrels per day per meter; or
    (4) Prove 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

[[Page 387]]

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]



Sec. 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 changes 
to previously approved measurement procedures.
    (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  deg.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.

[[Page 388]]

    (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]



Sec. 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 changes to previously approved commingling applications.
    (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 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]



Sec. 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.

[[Page 389]]



Sec. 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.



Sec. 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 if unitized operations are 
necessary to:
    (1) Prevent waste;
    (2) Conserve natural resources; or
    (3) Protect correlative rights, including Federal royalty interests, 
of a reasonably delineated and productive reservoir.
    (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. 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 
(Sec. 250.180) under the unit agreement, unless the Regional Supervisor 
orders or approves a suspension of production under Sec. 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

[[Page 390]]

initiation of actual development drilling or production operations and 
that time period would extend beyond your lease's primary term or any 
extension under Sec. 250.180, the unit operator must request and obtain 
MMS approval of a suspension of production under Sec. 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 
Sec. 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]



Sec. 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 Sec. 250.1301(b), MMS 
will initiate unitization under Sec. 250.1304.

[62 FR 5331, Feb. 5, 1997. Redesignated and amended at 63 FR 29479, 
29486, May 29, 1998]



Sec. 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 Sec. 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

[[Page 391]]

with the Regional Supervisor for approval.

[62 FR 5331, Feb. 5, 1997. Redesignated and amended at 63 FR 29479, 
29487, May 29, 1998]



Sec. 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 Secs. 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 
Sec. 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.



Sec. 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.

[[Page 392]]



Sec. 250.1401  Index table.

    The following table is an index of the sections in this subpart:

                          Sec.  250.1401  Table
------------------------------------------------------------------------
 
------------------------------------------------------------------------
Definitions...............................  Sec.  250.1402
What is the maximum civil penalty?........  Sec.  250.1403
Which violations will MMS review for        Sec.  250.1404
 potential civil penalties?.
When is a case file developed?............  Sec.  250.1405
When will MMS notify me and provide         Sec.  250.1406
 penalty information?.
How do I respond to the letter of           Sec.  250.1407
 notification?.
When will I be notified of the Reviewing    Sec.  250.1408
 Officer's decision?.
What are my appeal rights?................  Sec.  250.1409
------------------------------------------------------------------------


[62 FR 42668, Aug. 8, 1997. Redesignated and amended at 63 FR 29479, 
29487, May 29, 1998]



Sec. 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.
    I, me in a question or you in a response means the person, or agent 
of a person engaged in oil, gas, sulphur, or other minerals operations 
in the Outer Continental Shelf (OCS).
    Person means, in addition to a natural person, an association 
(including partnerships and joint ventures), a State, a political 
subdivision of a State, or a private, public, or municipal corporation.
    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.



Sec. 250.1403  What is the maximum civil penalty?

    The maximum civil penalty is $25,000 per day per violation.

[64 FR 9065, Feb. 24, 1999]



Sec. 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]



Sec. 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 Sec. 250.1404 exist. The Reviewing Officer will review the 
case file and determine if a civil penalty is

[[Page 393]]

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]



Sec. 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]



Sec. 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.



Sec. 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.



Sec. 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 Secs. 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 Sec. 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]

[[Page 394]]



                           Subpart O--Training

    Source: 62 FR 5322, Feb. 5, 1997, unless otherwise noted. 
Redesignated at 62 FR 67284, Dec. 24, 1997, and further redesignated at 
63 FR 29479, May 29, 1998.



Sec. 250.1500  Question index table.

    The table in this section lists frequently asked training questions 
and the location for the answers. The subjects are grouped as follows:
    (a) General training requirements--Secs. 250.1502 through 250.1507.
    (b) Departures from training requirements--Secs. 250.1508 through 
250.1513.
    (c) Training program accreditations--Secs. 250.1514 through 250.1520 
and Sec. 250.1524.
    (d) MMS testing information--Secs. 250.1521 through 250.1523.

                          Sec.  250.1500  Table
------------------------------------------------------------------------
        Frequently asked questions                  CFR citation
------------------------------------------------------------------------
What is MMS's goal for well control and     Sec.  250.1502
 production safety systems training?.
What type of training must I provide for    Sec.  250.1503
 my employees?.
What documentation must I provide to        Sec.  250.1504
 trainees?.
How often must I provide training to my     Sec.  250.1505
 employees and for how many hours?.
Where must I get training for my            Sec.  250.1506
 employees?.
Where can I find training guidelines for    Sec.  250.1507
 other topics?.
Can I get exception to the training         Sec.  250.1508
 requirements?.
Can my employees change job certification?  Sec.  250.1509
What must I do if I have temporary          Sec.  250.1510
 employees or on-the-job trainees?.
What must manufacturer's representatives    Sec.  250.1511
 in production safety systems do?.
May I use alternative training methods?...  Sec.  250.1512
What is MMS looking for when it reviews an  Sec.  250.1513
 alternative training program?.
Who may accredit training organizations to  Sec.  250.1514
 teach?.
How long is a training organization's       Sec.  250.1515
 accreditation valid?.
What information must a training            Sec.  250.1516
 organization submit to MMS?.
What additional requirements must a         Sec.  250.1517
 training organization follow?.
What are MMS's requirements for the         Sec.  250.1518
 written test?.
What are MMS's requirements for the hands-  Sec.  250.1519
 on simulator and well test?.
What elements must a basic course cover?..  Sec.  250.1520
If MMS tests employees at my worksite,      Sec.  250.1521
 what must I do?.
If MMS tests trainees at a training         Sec.  250.1522
 organization's facility, what must occur?.
Why might MMS conduct its own tests?......  Sec.  250.1523
Can a training organization lose its        Sec.  250.1524
 accreditation?.
------------------------------------------------------------------------


[62 FR 5322, Feb. 5, 1997. Redesignated and amended at 63 FR 29479, 
29487, 29488, May 29, 1998; 63 FR 34597, June 25, 1998]



Sec. 250.1501  Definitions.

    Terms used in this subpart have the following meaning:
    Alternative training methods means self-paced or team-paced training 
that may use a computer-based system such as compact disc interactive 
(CDI), compact disc read only memory (CDROM), or Laser Discs.
    Completed training means that the trainee successfully met MMS's 
requirements for that training.
    Employees means direct employees and contract employees of lessees.
    Floorhands means rotary helpers, derrickmen, or their equivalent.
    I or you means the lessee or contractor engaged in oil, gas or 
sulphur operations in the Outer Continental Shelf (OCS).
    Installing means both installing the original equipment and 
replacing the equipment.
    Lessee means the person, organization, agent, or designee authorized 
to explore, develop, and produce leased deposits.
    Maintaining means preventive maintenance, routine repair, and 
replacing defective components.
    Operating means testing, adjusting, calibrating, and recording test 
and calibration results for the equipment.
    Production safety systems employee means employees engaged in 
installing, repairing, testing, maintaining, or operating surface or 
subsurface safety devices and the platform employee who is responsible 
for production operations.
    Supervisors means the driller, toolpusher, operator's 
representative, or their equivalent.

[[Page 395]]

    Training means a basic or an advanced class in well control for 
drilling, well completion/well workover, well servicing, and production 
safety systems.
    Training organization means a party approved by MMS to teach well 
control for drilling, well completion/well workover, and well servicing, 
and production safety systems.
    Well-completion/well-workover (WO) well control includes small 
tubing operations.
    Well-servicing (WS) well control means snubbing and coil tubing.
    Well-workover rig means a drilling rig used for well completion/well 
workover.



Sec. 250.1502  What is MMS's goal for well control and production safety systems training?

    The goal is to ensure that employees who work in the following areas 
receive training that results in safe and clean operations:
    (a) Drilling well control;
    (b) WO well control;
    (c) WS well control; and
    (d) Production safety systems.



Sec. 250.1503  What type of training must I provide for my employees?

    You must provide training for your employees according to the table 
in this section.

------------------------------------------------------------------------
                                    Training
      Type of employee            requirements            Comments
------------------------------------------------------------------------
Drilling floorhand..........  Drilling well-
                               control course.\1\
                              Complete a well-      You must log the
                               control drill at      time it took to
                               the job site within   complete each drill
                               the time limit        in the driller's
                               prescribed by         log and furnish the
                               company operating     time to the
                               procedures.\2\.       floorhand.
                              Participate in well-  You must record the
                               control drills        date and time it
                               under subpart D of    took to complete
                               this part.\2\.        each drill in the
                                                     driller's log.
                              Receive copy of a
                               drilling well-
                               control manual.\2\
Drilling supervisor.........  Drilling well-
                               control course.\1\
                              Qualify to direct
                               well-control
                               operations.\1\
WO floorhands...............  WO well-control
                               course.\1\
                              Complete the          You must record the
                               qualifying test       date and time it
                               consisting of a       took to complete
                               well-control drill    each drill in the
                               at the job site       operations log.
                               within the time
                               limit set by
                               company
                               procedures.\2\.
                              Participate in
                               weekly well-control
                               drills under
                               subparts E and F of
                               this part.\2\
                              Receive a well-
                               control manual.\2\
WO supervisors..............  WO well-control
                               course.\1\
                              Qualify to direct
                               well-control
                               operations.\1\
WS work crews...............  At least one crew     Trained employee
                               member is trained     must be in work
                               in WS well            area at all times
                               control.\1\.          during snubbing or
                                                     coil tubing
                                                     operations.
                              At least one crew
                               member must be
                               qualified to direct
                               well-control
                               operations.\1\
Production safety systems     Must complete
 employees.                    training that
                               enables them to
                               install, test,
                               maintain, & operate
                               subsurface safety
                               devices.\1\
Employees who work in well    Either WO well-
 completion operations         control course or
 before or during tree         drilling well-
 installation.                 control course.\1\
------------------------------------------------------------------------
\1\ Employee may not work in the OCS unless this requirement is met.
\2\ Employee must complete this requirement before exceeding 6 months of
  cumulative employment.



Sec. 250.1504  What documentation must I provide to trainees?

    You must give your employees documents that show they have completed 
the training course(s) required for their job. The employees must carry 
the documents or keep them at the job site.



Sec. 250.1505  How often must I provide training to my employees and for how many hours?

    (a) You must ensure that applicable employees complete basic or 
advanced well-control training at least every 2 years. For example, if 
your employees complete a well-control course on October 31, 1998, they 
must again complete the training by October 31, 2000.

[[Page 396]]

    (b) You must ensure that applicable employees complete basic or 
advanced production safety systems training at least every 3 years. For 
example, if your employees complete production safety systems training 
on October 31, 1998, they must again complete the training by October 
31, 2001.
    (c) You must ensure that your employees have at least the amount of 
training listed in the table in Sec. 250.1505(c). The maximum number of 
hours per day of well control or production safety instruction time is 9 
hours.

                             Training Hours
------------------------------------------------------------------------
                                     Surface       Subsea
                                     option,      option,    No options,
      Basic/advanced course          minimum      minimum      minimum
                                      hours      hours \1\      hours
------------------------------------------------------------------------
Drilling (D).....................           28           32  ...........
Well Completion/Workover (WO)....           32           36  ...........
Well Servicing (WS)..............  ...........  ...........           18
Combination D/WO.................           40           44  ...........
Combination D/WS.................           44           48  ...........
Combination WO/WS................           48           52  ...........
Combination D/WO/WS..............           55           59  ...........
Production Safety Systems........  ...........  ...........          30
------------------------------------------------------------------------
\1\ The subsea option includes the minimum hours from the surface option
  plus 4 hours.


                         Well Control Transition
------------------------------------------------------------------------
           If your employees                 Then the employees must
------------------------------------------------------------------------
A. Completed a basic course on or after  A. Complete an appropriate
 March 7, 1996 or                         basic course within 2 years to
                                          maintain certification,\1\ or
B. Completed a basic course before       B. Complete an appropriate
 March 7, 1996.                           basic course by March 9, 1998
                                          .\2\
------------------------------------------------------------------------
\1\ Example A: If the effective date of this regulation is November 1,
  1996, and your employees completed a basic course in Drilling and
  Workover/Completion well control on December 9, 1995, your employees
  must complete a basic Drilling and Workover/Completion well-control
  course by December 9, 1997.
\2\ Example B: If the effective date of this regulation is November 1,
  1996, and your employees completed a basic course in Well Servicing
  [snubbing option] well control on November 15, 1994, your employees
  must complete a basic course in Well Servicing [snubbing option] by
  November 1, 1997.

    (e) For the first training course after March 7, 1997, you must 
ensure that your employee follows the following transition schedule 
table for production.

                          Production Transition
------------------------------------------------------------------------
           If your employees                 Then your employees must
------------------------------------------------------------------------
A. Completed a basic course on or after  A. Complete a basic course
 September 7, 1995, or                    within 3 years to maintain
                                          certification, or
B. Completed a basic course before       B. Complete a basic course by
 September 7, 1995.                       September 7, 1998.
------------------------------------------------------------------------

    (f) After your employee completes the transition training specified 
in paragraph (d) or (e) of this section, the training cycle will be 2 
years for well control and 3 years for production training (as shown in 
Sec. 250.1505 (a) and (b)).

[62 FR 5323, Feb. 5, 1997, as amended at 62 FR 7298, Feb. 18, 1997. 
Redesignated at 62 FR 67284, Dec. 24, 1997, further redesignated at 63 
FR 29479, May 29, 1998; 63 FR 34597, June 25, 1998]

[[Page 397]]



Sec. 250.1506  Where must I get training for my employees?

    You must provide training by a training organization or program 
approved by MMS.



Sec. 250.1507  Where can I find training guidelines for other topics?

    You can find guidelines in the subparts shown in the following 
table:

------------------------------------------------------------------------
                    Topic                         Subpart of part 250
------------------------------------------------------------------------
Pollution control...........................  C
Crane operations............................  A
Welding and burning.........................  A
Hydrogen sulfide............................  D
------------------------------------------------------------------------


[62 FR 5322, Feb. 5, 1997. Redesignated at 62 FR 67284, Dec. 24, 1997, 
and further redesignated at 63 FR 29479, May 29, 1998, as amended at 64 
FR 72794, Dec. 28, 1999]



Sec. 250.1508  Can I get an exception to the training requirements?

    MMS may grant an exception to well control or production safety 
systems training if:
    (a) MMS determines that the exception won't jeopardize the safety of 
your personnel or create a hazard to the environment; and
    (b) You need the exception because of unavoidable circumstances that 
make compliance infeasible or impractical.



Sec. 250.1509  Can my employees change job certification?

    Only if you ensure that the employees complete training for the new 
job before entering on duty.



Sec. 250.1510  What must I do if I have temporary employees or on-the-job trainees?

    You must ensure that temporary employees and on-the-job trainees 
complete the appropriate training unless a trained individual is 
directly supervising the employee.



Sec. 250.1511  What must manufacturer's representatives in production safety systems do?

    A manufacturer's representative who is working on company supplied 
equipment must:
    (a) Receive training by the manufacturer to install, service, or 
repair the specific safety device or safety systems; and
    (b) Have an individual trained in production safety systems (who is 
also capable of evaluating the impact of the work done) accompany her/
him.



Sec. 250.1512  May I use alternative training methods?

    (a) You may receive a 1-year provisional approval from MMS to use 
alternative training methods that may involve team or self-paced 
training using a computer-based system.
    (b) You may receive up to 3 additional years (4 years total) from 
MMS to use alternative training methods (through onsite reviews).



Sec. 250.1513  What is MMS looking for when it reviews an alternative training program?

    (a) The alternative training must teach methods to operate equipment 
that result in safe and clean operations.
    (b) MMS will determine, through onsite MMS reviews and unannounced 
audits during the provisional period, if the:
    (1) Training environment is conducive to learning;
    (2) Trainees interact effectively with the moderator or training 
administrator,
    (3) Trainees function as a team (for well control only); and
    (4) Tests are challenging and cover all important safety concepts 
and practical procedures to ensure safety.
    (c) MMS may also speak with the trainees to determine if the 
trainees felt the training met their needs for their job.



Sec. 250.1514  Who may accredit training organizations to teach?

    MMS may accredit a training organization or program.



Sec. 250.1515  How long is a training organization's accreditation valid?

    An accreditation is valid for a maximum of 4 years. A training 
organization may apply to MMS before the

[[Page 398]]

fourth anniversary of the effective accreditation date. The training 
organization must state the changes (additions and deletions) to the 
last approved training curriculum and plan.



Sec. 250.1516  What information must a training organization submit to MMS?

    (a) Two copies of the detailed plan that includes the:
    (1) Curriculum;
    (2) Names and credentials of the instructors;
    (3) Mailing and street address of the training facility and the 
location of the records;
    (4) Location for the simulator and lecture areas and how the 
training organization separates the areas;
    (5) Presentation methods (video, lecture, film, etc.);
    (6) Percentage of time for each presentation method;
    (7) Testing procedures and a sample test; and
    (8) List of any portions of the course that cover the subsea 
training option instead of the surface training option.
    (b) Two copies of the training manual.
    (c) A cross-reference that relates the requirements of this supbart 
to the elements in the program.
    (d) A copy of the handouts.
    (e) A copy of the training certificate that includes the following:
    (1) Candidate's full name;
    (2) Candidate's social security number,
    (3) Name of the training school;
    (4) Course name (e.g., basic WS well-control course);
    (5) Option (surface or subsea);
    (6) Training completion date;
    (7) Job classification (e.g., drilling supervisor); and
    (8) Certificate expiration date.
    (f) Course outlines identified by:
    (1) Name (e.g., ``WS well-control course'');
    (2) Type (basic or advanced); and
    (3) Option (surface or subsea).
    (g) Time (hours per student) for the following:
    (1) Teaching;
    (2) Using the simulator (for well control);
    (3) Hands-on training (for production safety systems); and
    (4) Completing the test (written and simulator).
    (h) Special instruction methods for students who respond poorly to 
conventional training (including oral assistance).
    (i) Additional materials (for the advanced training option) such as 
advanced training techniques or case studies.
    (j) Information on the 3-D simulator or test wells:
    (1) Capability for surface and/or subsea drilling well control, WO 
and completion training;
    (2) Capability to simulate lost circulation and secondary kicks; and
    (3) Types of kicks.



Sec. 250.1517  What additional requirements must a training organization follow?

    (a) The training organization must keep training records for each 
trainee for 5 years. For example, if a trainee completed a well-control 
course in 1996, the training organization may destroy the records at the 
end of the year 2001. The training organization must keep the following 
trainee record information:
    (1) Daily attendance record including complete student sign-in sheet 
and makeup time;
    (2) Written test and retest (including simulator test);
    (3) Evaluation of the trainee's simulator test or retest;
    (4) ``Kill sheets'' for simulator test or retest; and
    (5) Copy of the trainee's certificate.
    (b) Keep records of the training program for 5 years. The 5-year 
timeframe starts with the program approval date. For example, if a 
training program was accredited in 1995, at the end of the year 2000, 
the training organization may destroy the records for 1995. Keep the 
following training record information:
    (1) Complete and current training program plan and a technical 
manual;
    (2) A copy of each class roster; and
    (3) Copies of schedules and schedule changes.
    (c) Supply trainees with current copies of Government regulations on 
the training subject matter.

[[Page 399]]

    (d) Provide a certificate to each trainee who successfully completes 
training.
    (e) Ensure that the subsea training option has an additional 4 hours 
of training and covers problems in well control when drilling with a 
subsea blowout preventer (BOP) stack including:
    (1) Choke line friction determinations;
    (2) Using marine risers;
    (3) Riser collapse;
    (4) Removing trapped gas from the BOP after controlling a well kick; 
and
    (5) ``U'' tube effect as gas hits the choke line.
    (f) Ensure that trainees who are absent from any part of a course 
make up the missed portion within 14 days after the end of the course 
before providing a written or simulator test to the trainee.
    (g) Ensure that classes contain 18 or fewer candidates.
    (h) Furnish a copy of the training program and plan to MMS personnel 
for their use during an onsite review.
    (i) Submit the course schedule to the approving organization after 
approval of the training program, annually, and before any program 
changes. The schedule must include the:
    (1) Name of the course;
    (2) Class dates;
    (3) Type of course; and
    (4) Course location.
    (j) Provide all basic course trainees a copy of the training manual.
    (k) Provide all advanced course trainees handouts necessary to 
update the manuals the trainee has as a result of previous training 
courses.
    (l) When each course ends, send MMS a letter and a class roster. The 
class roster must contain the following information for each trainee:
    (1) Name of training organization;
    (2) Course location (e.g., Thibodeaux, Louisiana);
    (3) Trainee's full name;
    (4) Name of course (e.g., Drilling well control or WS well control);
    (5) Course type (i.e., basic or advanced training);
    (6) Options (e.g., subsea);
    (7) Date trainee completed course;
    (8) Name(s) of instructor(s) teaching the course;
    (9) The trainee's social security number;
    (10) Trainee's employer;
    (11) Actual job title of trainee;
    (12) Job of each awarded certificate; and
    (13) Test scores (including course element scores) for each 
successful trainee.
    (m) Ensure that test scores for combination training have a separate 
score element for each designation and for each option. For example, 
training in subsea drilling and in WO would have separate test scores 
for the drilling, WO, and for the subsea portion.



Sec. 250.1518  What are MMS's requirements for the written test?

    (a) The training organization must:
    (1) Administer the test at the training facility;
    (2) Use 70 percent as a passing grade for each course element 
(drilling, well completion, etc.);
    (3) Ensure that the tests are confidential and nonrepetitive;
    (4) Offer a retest, when necessary, using different questions of 
equal difficulty;
    (5) Allow open-book regulations and a formula sheet (without 
examples) for well control only; and
    (6) Allocate no more than the following amount of time to the 
minimum instruction time: 1 hour for a single course, 2 hours for a 
combination of two basic courses, or 2.5 hours for a combination of 
three or more courses.
    (b) A trainee who fails a retest must repeat the training and pass 
the test in order to work in the OCS in their job classification.



Sec. 250.1519  What are MMS's requirements for the hands-on simulator and well test?

    (a) The training organization must ensure that:
    (1) The test simulates a surface BOP (or subsea stack for the subsea 
option) and the simulator is 3-D with actual gauges and dials.
    (2) The instructor runs only one simulator and has a maximum of 
three students in each team.
    (3) The simulator test time allocated to the minimum instruction 
time is 1

[[Page 400]]

hour per course (i.e., 2 hours for a combination of two basic courses, 
etc.).
    (4) The trainees are able to:
    (i) Kill the well before removing the tree;
    (ii) Determine slow pump rates;
    (iii) Recognize kick warnings signs;
    (iv) Shut in a well;
    (v) Complete kill sheets;
    (vi) Initiate kill procedures;
    (vii) Maintain appropriate bottomhole pressure;
    (viii) Maintain constant bottomhole pressure;
    (ix) Recognize and handle unusual well-control situations;
    (x) Control the kick as it reaches the choke line; and
    (xi) Determine if kick gas or fluids are removed.
    (5) In the subsea option, the trainees are able to:
    (i) Determine choke line friction pressures for subsea BOP stacks; 
and
    (ii) Discuss and demonstrate procedures such as circulating the 
riser and removing trapped gas in a subsea BOP stack.
    (6) Offer a retest, when necessary, using different questions of 
equal difficulty.
    (b) A trainee who fails a retest must repeat the training and pass 
the test to work in the OCS in their job classification.

[62 FR 5326, Feb. 5, 1997, as amended at 62 FR 7298, Feb. 18, 1997. 
Redesignated at 62 FR 67284, Dec. 24, 1998]



Sec. 250.1520  What elements must a basic course cover?

    See Table (a) of this section for well control and Table (b) of this 
section for production safety systems. The checks in Table (a) indicate 
the required training elements that apply to each job. Tables (a) and 
(b) follow:

                                             Table (a)--Well Control
----------------------------------------------------------------------------------------------------------------
                                             Drilling                           WO
   Elements for basic training   ----------------------------------------------------------------       WS
                                       Super           Floor           Super           Floor
----------------------------------------------------------------------------------------------------------------
1. Hands-on:
    Training to operate choke     ..............           ..............           ..............
     manifold.
    Training to operate stand     ..............           ..............           ..............
     pipe.
    Training to operate mud room  ..............           ..............  ..............  ..............
     valves.
2. Care, handling &                                 ..............  ..............  ..............
 characteristics of drilling &
 completion fluids.
3. Care, handling &               ..............  ..............                    
 characteristics of well
 completion/well workover fluids
 & packer fluids.
4. Major causes of uncontrolled
 fluids from a well including:
    Failure to keep the hole               ..............           ..............  ..............
     full.
    Swabbing effect.............           ..............           ..............  ..............
    Loss of circulation.........           ..............           ..............  ..............
    Insufficient drilling fluid            ..............           ..............  ..............
     density.
    Abnormally pressured                   ..............           ..............  ..............
     formations.
    Effect of too rapidly                  ..............           ..............  ..............
     lowering of the pipe in the
     hole.
5. Importance & instructions of            ..............           ..............  ..............
 measuring the volume of fluid
 to fill the hole during trips.
6. Importance & instructions of            ..............  ..............  ..............  ..............
 measuring the volume of fluid
 to fill the hole during trips
 including the importance of
 filing the hole as it relates
 to shallow gas conditions.
7. Filling the tubing & casing    ..............  ..............  ..............           ..............
 with fluid to control
 bottomhole pressure.
8. Warning signals that indicate                                      ..............
 kick & conditions that lead to
 a kick.
9. Controlling shallow gas kicks           ..............  ..............  ..............  ..............
 and using diverters.
10. At least one bottomhole                ..............           ..............  ..............
 pressure well control method
 including conditions unique to
 a surface subsea BOP stack.
11. Installing, operating,                 ..............  ..............  ..............  ..............
 maintaining & testing BOP &
 diverter systems.
12. Installing, operating,        ..............  ..............           ..............  ..............
 maintaining & testing BOP
 systems.
13. Government regulations on:
    Emergency shutdown systems..  ..............  ..............  ..............  ..............  
    Production safety systems...  ..............  ..............  ..............  ..............  
    Drilling procedures.........           ..............  ..............  ..............  ..............
    Wellbore plugging &                    ..............           ..............  
     abandonment.

[[Page 401]]

 
    Pollution prevention & waste                                      
     management.
    Well completion & well        ..............  ..............           ..............  
     workover requirements
     (Subparts E & F of 30 CFR
     part 250).
14. Procedures & sequentials
 steps for shutting in a well:
    BOP system..................           ..............           ..............  
    Surface/subsurface safety     ..............  ..............  ..............  ..............  
     system.
    Choke manifold..............           ..............           ..............  ..............
15. Well control exercises with   ..............  ..............           ..............  ..............
 a simulator suitable for
 modeling well completion/well
 workover.
16. Well control exercises with            ..............  ..............  ..............  ..............
 a simulator suitable for
 modeling drilling.
17. Instructions & simulator or            ..............           ..............  ..............
 test well experience on
 organizing & directing a well
 killing operation.
18. At least two simulator                 ..............           ..............  ..............
 practice problems (rotate the
 trainees & have teams of 3 or
 less members).
19. Care, operation, & purpose                                        ..............
 [& installation (for
 supervisors)] of the well
 control equipment.
20. Limitations of the equipment           ..............           ..............  
 that may wear or be subjected
 to pressure.
21. Instructions in well control
 equipment, including:
    Surface equipment...........           ..............           ..............  
    Well completion/well                   ..............           ..............  
     workover, BOP & tree
     equipment.
    Downhole tools & tubulars...           ..............           ..............  ..............
    Tubing hanger, back pressure           ..............  ..............  ..............  
     valve (threaded/profile),
     landing nipples, lock
     mandrels for corresponding
     nipples & operational
     procedures for each, gas
     lift equipment & running &
     pulling tools operation.
    Packers.....................           ..............           ..............  ..............
22. Instructions in special
 tools & systems, such as:
    Automatic shutdown systems    ..............  ..............  ..............  ..............  
     (control points, activator
     pilots, monitor pilots,
     control manifolds &
     subsurface systems).
    Flow string systems (tubing,  ..............  ..............  ..............  ..............  
     mandrels & nipples, flow
     couplings, blast joints, &
     sliding sleeves).
    Pumpdown equipment (purpose,  ..............  ..............  ..............  ..............  
     applications, requirements,
     surface circulating
     systems, entry loops & tree
     connection/flange).
23. Instructions for detecting             ..............  ..............  ..............  ..............
 entry into abnormally pressured
 formations & warning signals.
24. Instructions on well                   ..............  ..............  ..............  ..............
 completion/well control
 problems.
25. Well control problems during
 well completion/well workover
 including:
    Killing a flow..............  ..............  ..............           ..............  ..............
    Simultaneous drilling,        ..............  ..............           ..............  ..............
     completion & workover
     operations on the same
     platform.
    Killing a producing well....  ..............  ..............           ..............  ..............
    Removing the tree...........  ..............  ..............           ..............  ..............
26. Calculations on the
 following:
    Fluid density increase that            ..............           ..............  ..............
     controls fluid flow into
     the wellbore.
    Fluid density to pressure              ..............  ..............  ..............  ..............
     conversion & the danger of
     formation breakdown under
     the pressure caused by the
     fluid column especially
     when setting casing in
     shallow formations.
    Fluid density to pressure     ..............  ..............           ..............  ..............
     conversion & the danger of
     formation breakdown under
     the pressure caused by
     fluid column.
    Equivalent pressures at the            ..............  ..............  ..............  ..............
     casing seat depth.
    Drop in pump pressure as               ..............           ..............  ..............
     fluid density increases; &
     the relationship between
     pump pressure, pump rate, &
     fluid density.
    Pressure limitations on                ..............           ..............  ..............
     casings.
    Hydrostatic pressure &                 ..............           ..............  ..............
     pressure gradient.
27. Unusual well control
 situations, including the
 following:
    Drill pipe is off the bottom           ..............           ..............  ..............
     or out of the hole/work
     string is off the bottom or
     out of the hole.
    Lost circulation occurs.....           ..............           ..............  ..............

[[Page 402]]

 
    Drill pipe is plugged/work             ..............           ..............  ..............
     string is plugged.
    There is excessive casing              ..............           ..............  ..............
     pressure.
    There is a hole in drill               ..............           ..............  ..............
     pipe/hole in the work
     string/hole in the casing
     string.
    Multiple completions in the   ..............  ..............           ..............  ..............
     hole.
28. Special well-control
 problems-drilling with a subsea
 stack (subsea students)
 includes:
    Choke line friction                    ..............           ..............  ..............
     determinations.
    Using marine risers.........           ..............           ..............  ..............
    Riser collapse..............           ..............           ..............  ..............
    Removing trapped gas from              ..............           ..............  ..............
     the BOP stack after
     controlling a well kick.
    ``U'' tube effect as gas               ..............           ..............  ..............
     hits the choke line.
29. Mechanics of various well
 controlled situations,
 including:
    Gas bubble migration &                 ..............           ..............  ..............
     expansion.
    Bleeding volume from a shut-           ..............           ..............  ..............
     in well during gas
     migration.
    Excessive annular surface              ..............           ..............  ..............
     pressure.
    Differences between a gas              ..............           ..............  ..............
     kick & a salt water and/or
     oil kick.
    Special well control                   ..............           ..............  ..............
     techniques (such as, but
     not limited to, barite
     plugs & cement plugs).
    Procedures & problems                  ..............           ..............  ..............
     involved when experiencing
     lost circulation.
    Procedures & problems                  ..............           ..............  
     involved when experiencing
     a kick while drilling in a
     hydrogen sulfide (H2S)
     environment.
    Procedures & problems--                ..............           ..............  ..............
     experiencing a kick during
     snubbing, coil-tubing, or
     small tubing operations and
     stripping & snubbing
     operations with work string.
30. Reasons for well completion/
 well workover, including:
    Reworking a reservoir to      ..............  ..............           ..............  
     control production.
    Water coning................  ..............  ..............           ..............  ..............
    Completing from a new         ..............  ..............           ..............  
     reservoir.
    Completing multiple           ..............  ..............           ..............  
     reservoirs.
    Stimulating to increase       ..............  ..............           ..............  
     production.
    Repairing mechanical failure  ..............  ..............           ..............  
31. Methods on preparing a well
 for entry:
    Using back pressure valves..  ..............  ..............           ..............  ..............
    Using surface & subsurface    ..............  ..............           ..............  
     safety systems.
    Removing the tree & tubing    ..............  ..............                    
     hangar.
    Installing & testing BOP &    ..............  ..............           ..............  
     wellhead prior to removing
     back pressure valves &
     tubing plugs.
32. Instructions in small tubing
 units:
    Applications (stimulation     ..............  ..............           ..............  ..............
     operations, cleaning out
     tubing obstructions, and
     plugback and squeeze
     cementing).
    Equipment description         ..............  ..............           ..............  ..............
     (derrick & drawworks, small
     tubing, pumps, weighted
     fluid facilities, and
     weighted fluids).
    BOP equipment (rams,          ..............  ..............           ..............  ..............
     wellhead connection, and
     check valve).
33. Methods for killing a
 producing well, including:
    Bullheading.................  ..............  ..............           ..............  
    Lubricating & bleeding......  ..............  ..............           ..............  
    Coil tubing.................  ..............  ..............           ..............  
    Applications (stimulation     ..............  ..............  ..............  ..............  
     operations, initiating
     flow, & cleaning out sand
     in tubing).
    Equipment description (coil   ..............  ..............  ..............  ..............  
     tubing, reel, injecting
     head, control assembly &
     injector hoist).
    BOP equipment (tree           ..............  ..............  ..............  ..............  
     connection or flange, rams,
     injector assembly &
     circulating system).
    Snubbing....................  ..............  ..............           ..............  
    Types (rig assist & stand     ..............  ..............  ..............  ..............  
     alone).
    Applications (running &       ..............  ..............  ..............  ..............  
     pulling production or kill
     strings, resetting weight
     on packers, fishing for
     lost wireline tools or
     parted kill strings &
     circulating cement or
     fluid).

[[Page 403]]

 
    Equipment (operating          ..............  ..............  ..............  ..............  
     mechanism, power supply,
     control assembly & basket,
     slip assembly, mast &
     counterbalance winch &
     access window).
    BOP equipment (tree           ..............  ..............  ..............  ..............  
     connection or flange, rams,
     spool, traveling slips,
     manifolds, auxiliary--full
     opening safety valve inside
     BOP, maintenance & testing).
34. The purpose & use of BOP
 closing units, including the
 following:
    Charging procedures include            ..............           ..............  ..............
     precharge & operating
     pressure.
    Fluid volumes (useable &               ..............           ..............  ..............
     required).
    Fluid pumps.................           ..............           ..............  ..............
    Maintenance that includes              ..............           ..............  ..............
     charging fluid & inspection
     procedures.
35. Instructions on stripping &            ..............  ..............  ..............  ..............
 snubbing operators & using the
 BOP system for working pipe in
 or out of a wellbore under
 pressure.
----------------------------------------------------------------------------------------------------------------


                  Table (b)--Production Safety Systems
------------------------------------------------------------------------
 
-------------------------------------------------------------------------
1. Government Regulations:
    Pollution prevention & waste management
    Requirements for well completion/well workover operations
2. Instructions in the following: (contained in, but not limited to, API
 RP 14C):
    Failures or malfunctions in systems that cause abnormal conditions &
     the detection of abnormal conditions
    Primary & secondary protection devices & procedures
    Safety devices that control undesirable events
    Safety analysis concepts
    Safety analysis of each basic production process component
    Protection concepts
3. Hands on training on safety devices covering, installing, operating,
 repairing or maintaining equipment:
    High-low pressure sensors
    High-low level sensors
    Combustible gas detectors
    Pressure relief devices
    Flow line check valves
    Surface safety valves
    Shutdown valves
    Fire (flame, heat, or smoke) detectors
    Auxiliary devices (3-way block & bleed valves, time relays, 3-way
     snap acting valves, etc.)
    Surface-controlled subsurface safety valves &/or surface-control
     equipment
    Subsurface-controlled subsurface safety valves
4. Instructions on inspecting, testing & maintaining surface &
 subsurface devices & surface control systems for subsurface safety
 valves
5. Instructions in at least one safety device that illustrates the
 primary operation principle in each class for safety devices:
    Basic operations principles
    Limits affecting application
    Problems causing equipment malfunction & how to correct these
     problems
    A test for proper actuation point & operation
    Adjustments or calibrations
    Recording inspection results & malfunctions
    Special techniques for installing safety devices
6. Instructions on the basic principle & logic of the emergency support
 system:
    Combustible & toxic gas detection system
    Liquid containment system
    Fire loop System
    Other fire detection systems
    Emergency shutdown system
    Subsurface safety valves
------------------------------------------------------------------------


[[Page 404]]


[62 FR 5326, Feb. 5, 1997, as amended at 62 FR 7298, Feb. 18, 1997. 
Redesignated at 62 FR 67284, Dec. 24, 1998]



Sec. 250.1521  If MMS tests employees at my worksite, what must I do?

    (a) You must allow MMS to test employees at your worksite.
    (b) You must identify your employees by:
    (1) Current job classification;
    (2) Name of the operator;
    (3) Name of the most recent basic or advanced course taken by your 
employees for their current job; and
    (4) Name of the training organization.
    (c) You must correct any deficiencies found by MMS. Steps for 
correcting deficiencies may include:
    (1) Isolating problems by doing more testing; and
    (2) Reassigning employees or conducting training (MMS will not 
identify the employees it tests).



Sec. 250.1522  If MMS test trainees at a training organization's facility, what must occur?

    (a) Training organizations must allow MMS to test trainees.
    (b) The trainee must pass the MMS-conducted test or a retest in 
order for MMS to consider that the trainee completed the training.



Sec. 250.1523  Why might MMS conduct its own tests?

    MMS needs to identify the effectiveness of a training program that 
provides for safe and clean operations.



Sec. 250.1524  Can a training organization lose its accreditation?

    Yes, an accredited organization can lose its accreditation. MMS may 
revoke or suspend an organization's accreditation for noncompliance with 
regulations or conditions of its accredited program, or assess civil 
penalties under subpart N of this part.



                      Subpart P--Sulphur Operations

    Source: 56 FR 32100, July 15, 1991, unless otherwise noted. 
Redesignated at 63 FR 29479, May 29, 1998.



Sec. 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.



Sec. 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.



Sec. 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

[[Page 405]]

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, 
G, I, J, M, N, and O 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.



Sec. 250.1603  Determination of sulphur deposit.

    (a) Upon receipt of a written request from the lessee, the District 
Supervisor 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.



Sec. 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 (H2S). 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 250.417 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 Sec. 250.417 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 Sec. 250.402 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 Sec. 250.403 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.

[[Page 406]]

    (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]



Sec. 250.1605  Drilling requirements.

    (a) Lessees of OCS sulphur leases shall conduct drilling operations 
in accordance with Secs. 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 Supervisor.
    (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 
Sec. 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 Supervisor 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 Supervisor. The type of 
information to be collected and reported will be determined by the 
District Supervisor 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 Secs. 250.203 and 250.204 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 Supervisor may 
require that additional surveys and soil borings be performed and the 
results submitted for review and evaluation by the District Supervisor 
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

[[Page 407]]

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 Sec. 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]



Sec. 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.



Sec. 250.1607  Field rules.

    When geological and engineering information in a field enables a 
District Supervisor to determine specific operating requirements, field 
rules may be established for drilling, well completion, or well workover 
on the District Supervisor'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 Supervisor or upon 
the request of a lessee.



Sec. 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

[[Page 408]]

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 Supervisor 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 Supervisor. 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 
Supervisor, 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 Supervisor 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 Supervisor 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 Supervisor. 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

[[Page 409]]

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.



Sec. 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.



Sec. 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

[[Page 410]]

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 Supervisor;
    (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 Supervisor.
    (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.



Sec. 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 Supervisor. Annular type BOP's shall be pressure tested with 
water to 70 percent of rated working pressure or as otherwise approved 
by the District Supervisor.
    (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

[[Page 411]]

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 Supervisor. 
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 Supervisor.



Sec. 250.1612  Well-control drills.

    Well-control drills shall be conducted for each drilling crew in 
accordance with the requirements set forth in Sec. 250.408 of this part 
or as approved by the District Supervisor.

[56 FR 32100, July 15, 1991. Redesignated and amended at 63 FR 29479, 
29487, May 29, 1998]



Sec. 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

[[Page 412]]

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.



Sec. 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 Sec. 250.410 
(b), (c), (d), and (e) of this part, except that the installation of an 
operable degasser in the mud system as required in Sec. 250.410(b)(8) is 
not required for sulphur operations.

[56 FR 32100, July 15, 1991. Redesignated and amended at 63 FR 29479, 
29487, May 29, 1998]



Sec. 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 Supervisor 
in lieu of the above requirements if cap rock casing has been set.



Sec. 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.



Sec. 250.1617  Application for permit to drill.

    (a) Prior to commencing the drilling of a well under an approved 
Exploration Plan, Development and Production Plan, or Development 
Operations

[[Page 413]]

Coordination Document, the lessee shall file Form MMS-123, APD, with the 
District Supervisor for approval. Prior to commencing operations, 
written approval from the District Supervisor must be received by the 
lessee unless oral approval has been given pursuant to Sec. 250.140 of 
this part.
    (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 Supervisor 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;

[[Page 414]]

    (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 
Supervisor.
    (d) Public information copies of the APD shall be submitted in 
accordance with Sec. 250.190 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]



Sec. 250.1618  Sundry notices and reports on wells.

    (a) Notices of the lessee's intention to change plans, make changes 
in major drilling equipment, deepen, sidetrack, or plug back a well, or 
engage in similar activities and subsequent reports pertaining to such 
operations shall be submitted to the District Supervisor on Form MMS-
124, Sundry Notices and Reports on Wells. Prior to commencing operations 
associated with the change, written approval must be received from the 
District Supervisor unless oral approval is obtained pursuant to 
Sec. 250.140 of this part.
    (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 Sec. 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]



Sec. 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 Supervisor. 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 Supervisor 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 Sec. 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 
Supervisor 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, Well Summary Report, or Form MMS-124, Sundry 
Notices and Reports on Wells, as appropriate.
    (c) Upon request by the Regional or District 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 Supervisor. 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 Supervisor 
in duplicate as soon as available but not later than 30 days after 
completion of such operations for each well.

[[Page 415]]

    (e) If the District Supervisor determines that circumstances 
warrant, the lessee shall submit any other reports and records of 
operations in the manner and form prescribed by the District Supervisor.

[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]



Sec. 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 Secs. 250.1620 through 250.1626 of this part and other provisions 
of this part as appropriate (see Secs. 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]



Sec. 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.



Sec. 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 Supervisor. 
Approval for such operations shall be requested on Form MMS-124. 
Approvals by the District Supervisor 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 Supervisor.
    (2) Within 30 days after completing the well-workover operation, 
except routine operations, Form MMS-124 shall be submitted to the 
District Supervisor 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]



Sec. 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 ccntinuously 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

[[Page 416]]

    (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.



Sec. 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 
1\1/4\ inch) as a work string; i.e., small-tubing operations, shall 
consist of the following:
    (1) For air line changes, the well shall be killed prior to 
beginning operations. The procedures for killing the well shall be 
included in the description of well-workover procedures in accordance 
with Sec. 250.1622 of this part. Under these circumstances, no BOP 
equipment is required.

[[Page 417]]

    (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]



Sec. 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 Supervisor. Annular type BOP's shall be pressure tested with 
water to 70 percent of rated working pressure or as otherwise approved 
by the District Supervisor.
    (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 Supervisor. 
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.

[[Page 418]]

    (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 Supervisor.



Sec. 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.



Sec. 250.1627  Production requirements.

    (a) The lessee shall conduct sulphur production operations in 
compliance with the approved Development and Production Plan 
requirements of Secs. 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]



Sec. 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 
Supervisor 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 
Supervisor. 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 Supervisor certifying that the new 
installations conform to the approved designs of this subpart.
    (c) Hydrocarbon handling vessels associated with fuel gas system. 
Hydrocarbon handling vessels associated with the

[[Page 419]]

fuel gas system shall be protected with a basic and ancillary surface 
safety system designed, analyzed, installed, tested, and maintained in 
operating condition in accordance with the provisions of API Recommended 
Practice for Analysis, Design, Installation and Testing of Basic Surface 
Safety Systems for Offshore Production Platforms (API RP 14C). If 
processing components are to be utilized, other than those for which 
Safety Analysis Checklists are included in API RP 14C, the analysis 
technique and documentation specified therein shall be utilized to 
determine the effects 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 Supervisor 
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 Supervisor. 
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) and the related 
Safety Analysis Function Evaluation chart (API RP 14C, subsection 4.3c);
    (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 Supervisor 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]



Sec. 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 Sec. 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 shall be designed, fabricated, code stamped, and 
maintained in accordance with applicable provisions of section I, IV, 
and VIII of the American Society of Mechanical

[[Page 420]]

Engineers (ASME) Boiler and Pressure Vessel Code.
    (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. 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 Supervisor. 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. Engine exhausts shall be equipped to comply with 
the insulation and personnel protection requirements of API RP 14C, 
section 4.2c(4). Exhaust piping from diesel engines shall 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 
Supervisor. 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 Supervisor;
    (iii) A firefighting system using chemicals may be used in lieu of a 
water system if the District Supervisor 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-

[[Page 421]]

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 Supervisor may require the installation and 
maintenance of a gas detector or alarm in any potentially hazardous 
area.
    (v) Fire- and gas-detection systems shall be an approved type, 
designed and installed in accordance with API RP 14C, API RP 14G, and 
API RP 14F, Recommended Practice for Design and Installation of 
Electrical Systems for Offshore Production Platforms.
    (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]



Sec. 250.1630  Safety-system testing and records.

    (a) Inspection and testing.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 shall be in accordance with API RP 14C, appendix D or for 
safety-system devices other than those listed in API RP 14C, Appendix D 
the analysis technique and documentation specified therein shall be 
utilized 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 shall be inspected and tested at 
least once each calendar month, but at no time shall 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) All pumps for firewater systems shall be inspected and operated 
weekly.
    (4) 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.
    (5) Prior to the commencement of production, the lessee shall notify 
the District Supervisor when the lessee is ready to conduct a 
preproduction test and inspection of the safety system. The lessee shall 
also notify the District Supervisor 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 
Supervisor. 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.



Sec. 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

[[Page 422]]

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.



Sec. 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).



Sec. 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.



Sec. 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.



PART 251--GEOLOGICAL AND GEOPHYSICAL (G&G) EXPLORATIONS OF THE OUTER CONTINENTAL SHELF--Table of Contents




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.

    Source: 62 FR 67284, Dec. 24, 1997, unless otherwise noted.



Sec. 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

[[Page 423]]

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

[[Page 424]]

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.

[[Page 425]]

    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.



Sec. 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.



Sec. 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.



Sec. 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.



Sec. 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.

[[Page 426]]

    (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.



Sec. 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.

[[Page 427]]



Sec. 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 given in Sec. 251.5, a drilling plan, 
an environmental report, and an application for permit to drill (Form 
MMS-123) 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.

[[Page 428]]

    (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 (Form MMS-123) 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

[[Page 429]]

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.



Sec. 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

[[Page 430]]

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.



Sec. 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 Sec. 251.7(b)(8). You must also 
comply with all other obligations specified in this part or in the 
permit.

[[Page 431]]



Sec. 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]



Sec. 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,

[[Page 432]]

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.



Sec. 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

[[Page 433]]

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.



Sec. 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 Secs. 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.



Sec. 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. MMS will release data and information that you or a third 
party submits and MMS retains, in accordance with paragraphs (b)(1) and 
(b)(2) 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:

[[Page 434]]



------------------------------------------------------------------------
  If you or a third party submit and MMS     The Regional Director will
                  retains                    disclose them to the public
------------------------------------------------------------------------
Geological data and information...........  10 years after issuing the
                                             permit.
Geophysical data..........................  50 years after you or a
                                             third party submit the
                                             data.
Geophysical information...................  25 years after you or a
                                             third party submit the
                                             information.
------------------------------------------------------------------------

    (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.
    (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 Secs. 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.



Sec. 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:

[[Page 435]]

    (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 Sec. 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]



PART 252--OUTER CONTINENTAL SHELF (OCS) OIL AND GAS INFORMATION PROGRAM--Table of Contents




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; Sec. 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.



Sec. 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.



Sec. 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

[[Page 436]]

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.

[[Page 437]]

    (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]



Sec. 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

[[Page 438]]

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]



Sec. 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:

[[Page 439]]

    (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.



Sec. 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]



Sec. 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 Sec. 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.



Sec. 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.

[[Page 440]]

    (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]



PART 253--OIL SPILL FINANCIAL RESPONSIBILITY FOR OFFSHORE FACILITIES--Table of Contents




                           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?

[[Page 441]]

               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--List of U.S. Geological Survey Topographic Maps

    Authority: 33 U.S.C. 2701 et seq.

    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



Sec. 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.



Sec. 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.

[[Page 442]]

    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:

[[Page 443]]

    (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.



Sec. 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

[[Page 444]]

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



Sec. 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.



Sec. 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]



Sec. 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 
Sec. 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.



Sec. 253.13  How much OSFR must I demonstrate?

    (a) The following general parameters apply to the amount of OSFR 
that you must demonstrate:

[[Page 445]]



------------------------------------------------------------------------
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:

------------------------------------------------------------------------
                                                            Applicable
        COF worst case oil-spill discharge volume         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:

------------------------------------------------------------------------
                                                            Applicable
        COF worst case oil-spill discharge volume         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.



Sec. 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 Sec. 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

[[Page 446]]

    (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.



Sec. 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 
Sec. 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



Sec. 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 Secs. 253.21 through 253.28;
    (b) Insurance under Sec. 253.29;
    (c) An indemnity under Sec. 253.30;
    (d) A surety bond under Sec. 253.31; or
    (e) An alternative method the Director approves under Sec. 253.32.



Sec. 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 Sec. 253.25 or an unencumbered net asset test under 
Sec. 253.28.
    (b) To establish the amount of self-insurance allowed, you must 
submit evidence of your net worth under Sec. 253.23 or evidence of your 
unencumbered assets under Sec. 253.26.
    (c) You must identify a U.S. agent for service of process.



Sec. 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.



Sec. 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.

[[Page 447]]

    (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).



Sec. 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.



Sec. 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.



Sec. 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 Sec. 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

[[Page 448]]

times the self-insurance amount requested for demonstration.



Sec. 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 Sec. 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.



Sec. 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.



Sec. 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 Sec. 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 Sec. 253.13;
    (2) No more than one insurance certificate may be used to cover each 
OSFR layer specified in Sec. 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

[[Page 449]]

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.



Sec. 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 Sec. 253.41; and
    (2) Does not exceed the amounts calculated using the net worth or 
unencumbered assets tests specified under Secs. 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.



Sec. 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 Sec. 253.41.



Sec. 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 
Sec. 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



Sec. 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 Sec. 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 Sec. 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.



Sec. 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

[[Page 450]]

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 
Sec. 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.



Sec. 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).



Sec. 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.



Sec. 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.

[[Page 451]]



Sec. 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



Sec. 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 Sec. 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.



Sec. 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 $25,000 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 Sec. 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]



        Subpart F--Claims for Oil-Spill Removal Costs and Damages



Sec. 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:

[[Page 452]]



------------------------------------------------------------------------
 If the reason for denial or
        nonpayment is                    then you may elect to
------------------------------------------------------------------------
(1) Not an assertion of        (i) Present your claim to any of the
 insolvency or petition in      responsible parties for the COF; or
 bankruptcy under 11 U.S.C.    (ii) Initiate a lawsuit against the
 chapter 7 or 11.               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            (i) Pursue any of the remedies in items
 insolvency or petition in      (1)(i) through (iii) of this table; or
 bankruptcy under 11 U.S.C.    (ii) Present your claim to any of the
 chapter 7 or 11.               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 Sec. 253.45. You must include any information you have 
regarding the existence or identity of possible guarantors.



Sec. 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.



Sec. 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.

        Appendix--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-

[[Page 453]]

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

[[Page 454]]

East; Mulberry Island West; New Harbor Islands; North Islands; Oak Mound 
Bayou; Oyster Bayou; Pass A Loutre East; Pass A Loutre West; Pass du 
Bois; Pass Tante Phine; Pecan Island; Pelican Pass; Peveto Beach; 
Pilottown; Plumb Bayou; Point Au Fer; Point Au Fer NE; Point Chevreuil; 
Point Chicot; Port Arthur South; Port Sulphur; Pte. Aux Marchuttes; 
Proctor Point; Pumpkin Islands; Redfish Point; Rollover Lake; Sabine 
Pass; Saint Joe Pass; Smith Bayou; South of South Pass; South Pass; 
Stake Islands; Taylor Pass; Texas Point; Three Mile Bay; Tigre Lagoon; 
Timbalier Island; Triumph; Venice; Weeks; West of Johnson Bayou; Western 
Isles Dernieres; Wilkinson Bay; Yscloskey.
    Mississippi (1:24,000 scale): Bay Saint Louis; Biloxi; Cat Island; 
Chandeleur Light; Deer Island; Dog Keys Pass; English Lookout; Gautier 
North; Gautier South; Grand Bay SW; Gulfport North; Gulfport NW; 
Gulfport South; Horn Island East; Horn Island West; Isle Au Pitre; 
Kreole; Ocean Springs; Pascagoula North; Pascagoula South; Pass 
Christian; Petit Bois Island; Saint Joe Pass; Ship Island; Waveland.
    Texas (1:24,000 scale): Allyns Bright; Anahuac; Aransas Pass; 
Austwell; Bacliff; Bayside; Big Hill Bayou; Brown Cedar Cut; Caplen; 
Carancahua Pass; Cedar Lakes East; Cedar Lakes West; Cedar Lane NE; 
Christmas Point; Clam Lake; Corpus Christi; Cove; Crane Islands NW; 
Crane Islands SW; Decros Point; Dressing Point; Estes; Flake; Freeport; 
Frozen Point; Galveston; Green Island; Hawk Island; High Island; 
Hitchcock; Hoskins Mound; Jones Creek; Keller Bay; Kleberg Point; La 
Comal; La Leona; La Parra Ranch NE; Laguna Vista; Lake Austin; Lake 
Como; Lake Stephenson; Lamar; Long Island; Los Amigos; Windmill; Maria 
Estella Well; Matagorda; Matagorda SW; Mesquite Bay; Mission Bay; 
Morgans Point; Mosquito Point; Mouth of Rio Grande; Mud Lake; North of 
Port Isabel NW; North of Port Isabel SW; Oak Island; Olivia; Oso Creek 
NE; Oyster Creek; Palacios; Palacios NE; Palacios Point; Palacios SE; 
Panther Point; Panther Point NE; Pass Cavallo SW; Pita Island; Point 
Comfort; Point of Rocks; Port Aransas; Port Arthur South; Port Bolivar; 
Port Ingleside; Port Isabel; Port Isabel NW; Port Lavaca East; Port 
Mansfield; Port O'Connor; Portland; Potrero Cortado; Potrero Lopeno NW; 
Potrero Lopeno SE; Potrero Lopeno SW; Rockport; Sabine Pass; San Luis 
Pass; Sargent; Sea Isle; Seadrift; Seadrift NE; Smith Point; South Bird 
Island; South Bird Island NW; South Bird Island SE; South of Palacios 
Point; South of Potrero Lopeno NE; South of Potrero Lopeno NW; South of 
Potrero Lopeno SE; South of Star Lake; St. Charles Bay; St. Charles Bay 
SE; St. Charles Bay SW; Star Lake; Texas City; Texas Point; The Jetties; 
Three Islands; Tivoli SE; Turtle Bay; Umbrella Point; Virginia Point; 
West of Johnson Bayou; Whites Ranch; Yarborough Pass.



PART 254--OIL-SPILL RESPONSE REQUIREMENTS FOR FACILITIES LOCATED SEAWARD OF THE COAST LINE--Table of Contents




                           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.

[[Page 455]]

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



Sec. 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 
Sec. 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.



Sec. 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 Sec. 254.30) after the 
effective date of this rule. The Regional Supervisor may extend this 
deadline upon request.



Sec. 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

[[Page 456]]

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 Sec. 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.



Sec. 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.



Sec. 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.



Sec. 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.

[[Page 457]]

    District Supervisor 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.

[[Page 458]]

    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.



Sec. 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.



Sec. 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]



Sec. 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]

[[Page 459]]



    Subpart B--Oil-Spill Response Plans for Outer Continental Shelf 
                               Facilities



Sec. 254.20  Purpose.

    This subpart describes the requirements for preparing spill-response 
plans for facilities located on the OCS.



Sec. 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.



Sec. 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.



Sec. 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

[[Page 460]]

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.



Sec. 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 Sec. 254.43.



Sec. 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.



Sec. 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 Sec. 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

[[Page 461]]

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 Sec. 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.



Sec. 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.



Sec. 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

[[Page 462]]

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.



Sec. 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 Sec. 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 Sec. 254.42. You must designate a location where you 
keep the records of these exercises.



Sec. 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



Sec. 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.



Sec. 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.

[[Page 463]]

    (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.



Sec. 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.

[[Page 464]]

    (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.



Sec. 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.



Sec. 254.44  Calculating response equipment effective daily recovery capacities.

    (a) You are required by Sec. 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 Sec. 254.45 (b) and (c).



Sec. 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.



Sec. 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

[[Page 465]]

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.



Sec. 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 Sec. 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 
Sec. 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



Sec. 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 Secs. 254.51, 254.52, and 254.53.

[[Page 466]]



Sec. 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 Sec. 254.3 and contact the appropriate regional MMS 
office if you have any questions on how to prepare this Regional 
Response Plan.



Sec. 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.



Sec. 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 Sec. 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.



Sec. 254.54  Spill prevention for facilities located in State waters seaward of the coast line.

    In addition to your response plan, you must submit to the Regional 
Supervisor a description of the steps you are taking to prevent spills 
of oil or mitigate a substantial threat of such a discharge. You must 
identify all State or Federal safety or pollution prevention 
requirements that apply to the prevention of oil spills from your 
facility, and demonstrate your compliance with these requirements. You 
also should include a description of industry safety and pollution 
prevention standards your facility meets. The Regional Supervisor may 
prescribe additional equipment or procedures for spill prevention if it 
is determined that your efforts to prevent spills do not reflect good 
industry practices.



PART 256--LEASING OF SULPHUR OR OIL AND GAS IN THE OUTER CONTINENTAL SHELF--Table of Contents




  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.

[[Page 467]]

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

256.14  Definitions.
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.
256.64  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.

    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



Sec. 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

[[Page 468]]

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]



Sec. 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]



Sec. 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.



Sec. 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]



Sec. 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;

[[Page 469]]

    (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]



Sec. 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]



Sec. 256.8  Leasing maps and diagrams.

    (a) Any area of the OCS which has been appropriately platted as 
provided

[[Page 470]]

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.



Sec. 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]



Sec. 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.



Sec. 256.12  Supplemental sales.

    (a) The Secretary may conduct a supplemental sale in accordance with 
the provisions of this section.

[[Page 471]]

    (b) Supplemental sales shall be governed by the regulations in this 
part, except Sec. 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



Sec. 256.14  Definitions.

    As used in this subpart, the term--Affected State and affected 
States means Maine, New Hampshire, Massachusetts, Rhode Island, 
Connecticut, New York, New Jersey, Pennsylvania, Delaware, Maryland, 
Virginia, North Carolina, South Carolina, Georgia, Florida, Alabama, 
Mississippi, Louisiana, Texas, California, Oregon, Washington, and 
Alaska.

[44 FR 38276, June 29, 1979. Redesignated at 47 FR 47006, Oct. 22, 1982; 
47 FR 50684, Nov. 9, 1982]



Sec. 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]



Sec. 256.17  Review by State and local governments and other persons.

    (a)(1) The Secretary shall prepare a proposed leasing program. At 
least 60

[[Page 472]]

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]



Sec. 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 Secs. 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]



Sec. 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 Sec. 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



Sec. 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

[[Page 473]]

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



Sec. 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]



Sec. 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



Sec. 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 Sec. 256.12 of

[[Page 474]]

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]



Sec. 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



Sec. 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]



Sec. 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.



Sec. 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

[[Page 475]]

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



Sec. 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]



Sec. 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 Sec. 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]

[[Page 476]]



Sec. 256.38  Joint bidding provisions.



Sec. 256.40  Definitions.

    The following definitions shall be applicable to Sec. 256.38 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 Sec. 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

[[Page 477]]

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 H10 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]



Sec. 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 Sec. 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 Sec. 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 Sec. 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 
Secs. 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,

[[Page 478]]

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]



Sec. 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 Sec. 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  deg.F.
    (e)(1) For purposes of computing production of natural gas under 
Sec. 256.41 of this part, chargeability under this section, and 
reporting under Sec. 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.

[[Page 479]]

    (2) For purposes of computing production of liquefied petroleum 
products under Sec. 256.41 of this part, chargeability under 
Sec. 256.46(g) of this part, 1.454 barrels of natural gas liquids at 60 
deg.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]



Sec. 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 Sec. 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 Sec. 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 Sec. 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]



Sec. 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).

[[Page 480]]

    (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 
Sec. 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 
Sec. 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]



Sec. 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 Sec. 256.35(b) of this part, or 
disqualified under Sec. 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

[[Page 481]]

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 Sec. 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 Sec. 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]



Sec. 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]



Sec. 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



Sec. 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

[[Page 482]]

    (3) Maintain a lease or areawide bond in the amount required in 
Sec. 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 areas offshore the Gulf of Mexico and 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 Sec. 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 
alternate form of security maintained under this section, the surety's 
remaining liability under the bond or alternate 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 alternate 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 alternate types of security instruments instead 
of providing a bond if the Regional Director determines that the 
alternate security protects the interests of the United States to the 
same extent as the required bond.
    (1) If you pledge an alternate 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 alternate 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 Sec. 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]



Sec. 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.

[[Page 483]]

    (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 Secs. 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

[[Page 484]]

    (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]



Sec. 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 Sec. 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 Sec. 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]



Sec. 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 Secs. 256.52 and

[[Page 485]]

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]



Sec. 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 Sec. 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 
Sec. 250.700 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]



Sec. 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 Sec. 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

[[Page 486]]

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       Include a report by an
 recently completed fiscal year.             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     Your guarantor's financial
 quarters in the current fiscal year.        officer certifies to be
                                             correct.
(iii) Additional information as requested   Your guarantor's financial
 by the Regional Director.                   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.

[[Page 487]]

    (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 Sec. 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]



Sec. 256.58  Termination of the period of liability and cancellation of a bond.

    This section defines the terms and conditions under which the 
Regional Director may terminate the period of liability of a bond or 
cancel a bond.
    (a) When the surety under your bond requests termination of the 
period of liability under its bond, the Regional Director will terminate 
the period of liability under your bond and demand that you provide a 
replacement bond of equivalent amount.
    (1) Termination of the period of liability under a bond does not 
release the surety of that bond.
    (2) Your surety is responsible for all obligations and liabilities 
that accrue before the effective date of the Regional Director's 
termination of the period of liability under its bond.
    (b) The Regional Director's cancellation or release of a bond may 
include lease obligations that accrue before the effective date of the 
cancellation only when:
    (1) The Regional Director determines that there are no outstanding 
obligations; or
    (2) You furnish a replacement bond:
    (i) In which your new surety agrees to assume all outstanding 
liabilities under the bond that is to be canceled; and
    (ii) That is in an amount equal to or greater than the amount of the 
bond that is to be canceled.
    (c) The Regional Director will issue a written instrument to cancel 
or release your bond. This instrument will subject the bond to automatic 
reinstatement, as if no cancellation or release had occurred, if:

[[Page 488]]

    (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 is materially 
false when the bond is canceled, or released.

[62 FR 27958, May 22, 1997]



Sec. 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]

[[Page 489]]



            Subpart J--Assignments, Transfers, and Extensions



Sec. 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 Sec. 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 Sec. 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 G.
    (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]



Sec. 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 Sec. 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,

[[Page 490]]

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) A nonrefundable filing fee of $185 must accompany an application 
for approval of any instrument of transfer required to be filed. MMS 
periodically will amend the filing fee based on its experience with the 
costs for administering lease transfer applications. If the costs 
increase by more than the CPI ``U,'' MMS will provide notice and 
opportunity for comment before changing the filing fee. For lesser cost 
increases or cost reductions MMS will change the fee without such 
procedures. Any document not required to be filed by these regulations 
but submitted for record purposes shall be accompanied by a 
nonrefundable fee of $25 per lease affected. Such documents may be 
rejected at the discretion of the authorized officer.
    (b) An attorney in fact, in behalf of the holder of a lease, 
operating rights or sublease, shall furnish evidence of authority to 
execute the assignment or application for approval and the statement 
required by Sec. 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 
Secs. 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 Sec. 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

[[Page 491]]

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]



Sec. 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.



Sec. 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.



Sec. 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.



Sec. 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]



Sec. 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.



Sec. 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

[[Page 492]]

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]



Sec. 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



Sec. 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.



Sec. 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



Sec. 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

[[Page 493]]

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]



Sec. 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



Sec. 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.

[[Page 494]]

           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:

------------------------------------------------------------------------
                                                         Amount of cash
   Tract No.*     Total amount bid   Amount per acre     submitted with
                                     (or per hectare)         bid
------------------------------------------------------------------------
 
 
------------------------------------------------------------------------
*Or, if tract numbers are not used, Protraction Diagram or Leasing Map
  and block number.


------------------------------------------------------------------------
                                    Proportionate
                                     interest of
     Bidder qualification No.         company(s)    Name and address of
                                      submitting      bidding company
                                         bid
------------------------------------------------------------------------
---- Misc. No.....................  .............  .....................
------------------------------------------------------------------------

------------------------,
Authorized signatory's name and title.

[47 FR 25972, June 16, 1982. Redesignated at 47 FR 47006, Oct. 22, 1982]



PART 259--MINERAL LEASING: DEFINITIONS--Table of Contents




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.



Sec. 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]



Sec. 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]



PART 260--OUTER CONTINENTAL SHELF OIL AND GAS LEASING--Table of Contents




                      Subpart A--General Provisions

Sec.
260.001  Purpose and scope.
260.002  Definitions.

                       Subpart B--Bidding Systems

260.101  Purpose and scope.
260.102  Definitions.

[[Page 495]]

260.110  Bidding systems.
260.111  Criteria for selection of bidding systems and bidding system 
          components.

Subpart C [Reserved]

                        Subpart D--Joint Bidding

260.301  Purpose.
260.302  Definitions.
260.303  Joint bidding requirements.

    Authority: 43 U.S.C. 1331 and 1337.

    Source: 45 FR 9539, Feb. 12, 1980, unless otherwise noted. 
Redesignated at 48 FR 1182, Jan. 11, 1983.



                      Subpart A--General Provisions



Sec. 260.001  Purpose and scope.

    The purpose of this part 260 is to implement OCSLA, 43 U.S.C. 1331 
et seq., as amended, by providing regulations to foster competition 
including, but not limited to, regulations to prohibit joint bidding for 
development rights by certain types of joint ventures; the 
implementation of alternative bidding systems (including suspension of 
royalties for a period, volume, or value of production); and the 
establishment of diligence requirements for Federal OCS leases issued 
under the OCSLA.

[61 FR 3804, Feb. 2, 1996]



Sec. 260.002  Definitions.

    For purposes of this part 260:
    OCSLA means the Outer Continental Shelf Lands Act, (43 U.S.C. 1331 
et seq.), as amended.
    OCS lease means a Federal lease for oil and gas issued under the 
OCSLA.
    Person includes, in addition to a natural person, an association, a 
State, or a private, public, or municipal corporation.

[45 FR 9539, Feb. 12, 1980. Redesignated at 48 FR 1182, Jan. 11, 1983, 
as amended at 61 FR 3804, Feb. 2, 1996]



                       Subpart B--Bidding Systems



Sec. 260.101  Purpose and scope.

    (a) This subpart establishes the several bidding systems that may be 
utilized in connection with the offering and sale of Federal leases for 
the exploration, development and production of oil and gas resources 
located on the OCS.
    (b) Only bidding systems established by his subpart shall be 
utilized in OCS lease sales.



Sec. 260.102  Definitions.

    For purposes of this subpart B--
    Eligible lease means a lease that results from a sale held after 
November 28, 1995; is located in the Gulf of Mexico in water depths 200 
meters or deeper; lies wholly west of 87 degrees, 30 minutes West 
longitude; and is offered subject to a royalty-suspension volume 
authorized by statute.
    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 and has submitted 
a bid higher than any other bids by qualified bidders on the same tract.
    Highest royalty rate means the highest per centum rate payable to 
the United States, as specified in the lease, in amount or value of the 
production saved, removed or sold.
    Lowest royalty rate means the lowest per centum rate payable to the 
United States, as specified in the lease, in amount or value of the 
production saved, removed or sold.
    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.
    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.
    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

[[Page 496]]

official protraction diagram prepared by 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 production period, 
which value is determined in accordance with Sec. 260.110(b).

[45 FR 9539, Feb. 12, 1980. Redesignated at 48 FR 1182, Jan. 11, 1983, 
as amended at 61 FR 12027, Mar. 25, 1996; 63 FR 2629, Jan. 16, 1998]



Sec. 260.110  Bidding systems.

    (a) A single bidding system selected from those listed in this 
paragraph shall be applied to each tract included in an OCS lease sale.
    (1) Cash bonus bid with a fixed royalty rate of not less than 12\1/
2\ per centum in amount or value of the production saved, removed or 
sold and an annual rental. (i) The royalty rate to be paid by the 
highest responsible qualified bidder shall be a percentage of the amount 
or value of the production saved, removed or sold. Such royalty rate 
shall not be less than 12\1/2\ per centum at the beginning of the lease 
period in amount or value of production and shall be specified in the 
notice of OCS lease sale published in the Federal Register.
    (ii) The amount of cash bonus to be paid is determined by the 
qualified bidder submitting the bid. Any deferment and the schedule of 
payments shall be included in the notice of OCS lease sale published in 
the Federal Register.
    (iii) The annual rental to be paid by the highest responsible 
qualified bidder and any amounts creditable against future royalties 
shall be specified in the notice of sale published in the Federal 
Register.
    (2) Royalty rate bid based on per centum in amount or value of the 
production saved, removed or sold, with a fixed cash bonus and an annual 
rental. (i) The royalty rate to be paid is determined by the qualified 
bidder submitting the bid and shall be based on a percentage of the 
amount or value of the production saved, removed, or sold.
    (ii) The cash bonus to be paid by the highest responsible qualified 
bidder shall be an amount specified in the notice of OCS lease sale 
published in the Federal Register.
    (iii) Rental payment amounts must be as specified in paragraph 
(a)(1)(iii) of this section.
    (3) Cash bonus bid with diminishing or sliding royalty rate of not 
less than 12\1/2\ per centum at the beginning of the lease period in 
amount or value of the production saved, removed, or sold, and annual 
rental. (i)(A) The royalty rate to be paid by the highest responsible 
qualified bidder shall be a percentage of the amount or value of the 
production saved, removed or sold. The royalty rate shall be calculated 
by utilizing either a sliding scale formula, which relates the royalty 
rate established thereby to the adjusted value of the oil and gas 
produced during the production period, or a schedule that establishes 
the royalty rate that will be applied to specified ranges of adjusted 
value of production. The description of the sliding scale formula or 
schedule shall include the relationship between adjusted value of 
production and royalty rate, and a stipulation of the lowest royalty 
rate and highest royalty rate. The sliding scale formula or schedule 
shall be included in the lease issued to the person who is the 
successful bidder as one of the lease terms and conditions.
    (B) The royalty rate shall not be less than 12\1/2\ per centum at 
the beginning of the lease period in amount or value of the production 
saved, removed or sold and shall be specified in the notice of OCS lease 
sale published in the Federal Register.
    (C) Royalty payment calculation. (1) The royalty rate utilized in 
the calculation of royalty payments is based on an adjusted value of 
production, and is established through application of a sliding scale 
formula or a schedule to the adjusted value of production.
    (2) The adjusted value of production shall be determined by applying 
an inflation factor to the actual value of production.
    (3) The established royalty rate is applied to the actual value of 
production, which results in the determination of amount in dollars to 
be paid to the United States by the person awarded the lease or the 
amount of royalty oil

[[Page 497]]

and gas to be taken in kind by the United States.
    (4) The production period, inflation factor and procedures for 
making the inflation adjustment and for determining the value or amount 
of production shall be stated in the notice of sale published in the 
Federal Register.
    (ii) The amount of cash bonus to be paid is determined by the 
qualified bidder submitting the bid. Any deferment and the schedule of 
payments shall be included in the notice of OCS lease sale published in 
the Federal Register.
    (iii) Rental payment amounts must be as specified in paragraph 
(a)(1)(iii) of this section.
    (4) Cash bonus bid with a fixed share of the net profits of no less 
than 30 per centum to be derived from the production of oil and gas from 
the lease area and a fixed annual rental--(i) Net profit share payment 
calculation. The amount of the net profit share payment to the United 
States by the person awarded the lease shall be determined for each 
month by multiplying the net profit share base times the net profit 
share rate, in accordance with Sec. 220.022.
    (A) Net profit share base. (1) The net profit share base shall be 
calculated in accordance with Sec. 220.021.
    (2) The capital recovery factor needed to calculate the allowance 
for capital recovery, in accordance with Sec. 220.020, shall be 
specified in the notice of OCS lease sale published in the Federal 
Register and may vary from tract to tract.
    (B) Net profit share rate. The net profit share rate, which 
determines the fixed share of the net profits owed to the United States, 
shall be a percentage that is specified in the notice of OCS lease sale 
published in the Federal Register. Such net profit share rate shall not 
be less than 30 percent of the net profit share base and may vary from 
tract to tract.
    (ii) The amount of cash bonus to be paid is determined by the person 
submitting the bid. Any deferment and the schedule of payments shall be 
included in the notice of OCS lease sale published in the Federal 
Register.
    (iii) The annual rental to be paid by the person awarded the lease 
shall be the amount specified in the notice of OCS lease sale published 
in the Federal Register.
    (5) Cash bonus bid with a variable royalty rate or rates during one 
or more production periods in amount or value of the production saved, 
removed or sold, and an annual rental. MMS may suspend or defer the 
royalty due for a period, volume, or value of production. Such 
suspensions or deferrals may vary based on changes in the prices of oil 
and/or gas as specified in the notice of sale published in the Federal 
Register.
    (i) The royalty rate due on production may be less than 12\1/2\ per 
centum, but greater than zero per centum, at any designated time during 
the lease period based on the amount or value of production saved, 
removed, or sold. Royalty may be suspended or deferred for a period, 
volume, or value of production. The applicable royalty rate(s) and 
suspension or deferral magnitudes or formulas shall be specified in the 
notice of sale published in the Federal Register.
    (ii) The amount and the procedure for payment of a cash bonus must 
be as specified in paragraph (a)(1)(ii) of this section.
    (iii) Rental payment amounts must be as specified in paragraph 
(a)(1)(iii) of this section.
    (6) Cash bonus bid with a royalty rate or rates based on formula(s) 
or schedule(s) during one or more production periods in amount or value 
of the production saved, removed or sold, and an annual rental. Royalty 
may be suspended or deferred for a period, volume, or value of 
production. Such a suspension or deferral may vary based on changes in 
the prices of oil and/or gas as specified in the notice of sale 
published in the Federal Register.
    (i) The royalty due on production shall be specified as a percentage 
of the amount or value of the production saved, removed, or sold. When 
the value of production is used, by unit or in aggregate, the royalty 
rate will be determined based on prices for oil and/or gas as specified 
in the notice of sale published in the Federal Register.
    (A) The lessee must calculate the royalty due using the formula or 
schedule specified in the lease based on the adjusted amount or indexed 
value of the oil and gas produced. The formula

[[Page 498]]

or schedule will describe the relationship between the adjusted or 
actual amount of production, indexed value, or indexed price, and the 
royalty rate. It will stipulate the lowest and highest royalty rates.
    (B) The royalty rate formula or schedule and the suspension or 
deferral magnitudes or formulas shall be specified in the notice of sale 
published in the Federal Register.
    (C) Royalty payment calculation.
    (1) The royalty rate used to calculate the royalty due on production 
is based on an adjusted or actual amount of production, indexed value, 
or indexed price and is set through application of the specified formula 
or schedule to the designated production period.
    (2) The lessee will determine the adjusted amount or indexed value, 
or indexed price by applying an index or inflation factor specified in 
the lease to the actual amount or value of production, or to the 
adjusted price.
    (3) The lessee must apply the royalty rate to the actual value of 
production. The result is the amount in dollars that the lessee must pay 
to the United States, or the amount of royalty oil and/or gas that the 
United States will take in kind.
    (4) The production period, inflation factor and procedures for 
making the inflation adjustment and for determining the value or amount 
of production shall be stated in the notice of sale published in the 
Federal Register.
    (ii) The amount and the procedure for payment of a cash bonus must 
be as specified in paragraph (a)(1)(ii) of this section.
    (iii) Rental payment amounts must be as specified in paragraph 
(a)(1)(iii) of this section.
    (7) Cash bonus bid with a royalty rate of not less than 12\1/2\ per 
centum fixed in amount or value of the production saved, removed or 
sold, and with suspension of royalties for a period, volume, or value of 
production, and an annual rental. Royalty may be suspended for a period, 
volume, or value of production. Such a suspension may vary based on 
changes in the prices of oil and/or gas as specified in the notice of 
sale published in the Federal Register.
    (i) Except for a period of suspension, the royalty rate due on 
production will be specified as a percentage of the amount or value of 
the production saved, removed, or sold. The applicable royalty rate 
shall be specified in the notice of the lease sale published in the 
Federal Register. When the royalty rate is applied to the value of 
production, by unit or in aggregate, the royalty rate will be determined 
based on the prices for oil and/or gas as specified in the notice of 
sale published in the Federal Register.
    (A) The lessee must calculate the royalty due using the formula or 
schedule specified in the lease agreement based on the adjusted amount 
or indexed value of the oil and gas produced. The formula or schedule 
will describe the relationship between adjusted or actual amount of 
production, indexed value, or indexed price, and the royalty rate. It 
will stipulate the lowest and highest royalty rates that may apply.
    (B) The formula or schedule for royalty due on production and the 
suspension magnitudes or formulas shall be specified in the notice of 
sale published in the Federal Register.
    (ii) The amount and the procedure for payment of a cash bonus must 
be as specified in paragraph (a)(1)(ii) of this section.
    (iii) Rental payment amounts must be as specified in paragraph 
(a)(1)(iii) of this section.
    (b) The value basis for determining the actual value of production 
and for purposes of computing royalty in accordance with the bidding 
systems established by paragraph (a) of this section shall be as 
described in 30 CFR 206.102, 206.152, and 206.153; Provided, however, 
That with respect to oil, the first sale of which is controlled under 10 
CFR part 212, the value shall not exceed the lawful first sale price of 
such oil; and Provided further, That with respect to gas, the value 
shall not exceed the sale price established by the Federal Energy 
Regulatory Commission.
    (c) MMS may, by rule, add to or modify the bidding systems listed in 
paragraph (a) of this section, in accordance with the procedural 
requirements of OCSLA, 43 U.S.C. 1331 et seq., as amended by Pub. L. 95-
372, 92 Stat. 629.

[[Page 499]]

    (d) This paragraph explains how the royalty-suspension volumes in 
section 304 of the Outer Continental Shelf Deep Water Royalty Relief 
Act, Public Law 104-58, apply to eligible leases. For purposes of this 
paragraph, any volumes of production that are not royalty bearing under 
the lease or the regulations in this chapter do not count against 
royalty-suspension volumes. Also, for the purposes of this paragraph, 
production includes volumes allocated to a lease under an approved unit 
agreement.
    (1) Your eligible lease may receive a royalty-suspension volume only 
if your lease is in a field where no current lease produced oil or gas 
(other than test production) before November 28, 1995. Paragraph (d) of 
this section applies only to eligible leases in fields that meet this 
condition.
    (2) We will assign your lease to an existing field or designate a 
new field and will notify you and other affected lessees of that 
assignment. Within 15 days of that notification, you or any of the other 
affected lessees may file a written request with the Director, MMS, for 
reconsideration accompanied by a statement of reasons. The Director will 
respond in writing either affirming or reversing the assignment 
decision. The Director's decision is final for the Department and is not 
subject to appeal to the Interior Board of Land Appeals under 30 CFR 
part 290 and 43 CFR part 4.
    (3) The Final Notice of Sale will specify the water depth for each 
eligible lease. Our determination of water depth for each lease is final 
once we issue the lease. The Notice also will specify the royalty-
suspension volume applicable to each water depth. The minimum royalty-
suspension volumes for fields are:
    (i) 17.5 million barrels of oil equivalent (MMBOE) in 200 to 400 
meters of water;
    (ii) 52.5 MMBOE in 400 to 800 meters of water; and
    (iii) 87.5 MMBOE in more than 800 meters of water.
    (4) 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 eligible lease(s) in that field. The 
determination is based on the royalty-suspension volumes specified in 
paragraph (d)(3) of this section.
    (5) If a new field consists of eligible leases in different water 
depth categories, the royalty-suspension volume associated with the 
deepest eligible lease applies.
    (6) 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.
    (7) If a field consists of more than one eligible lease, payment of 
royalties on the eligible leases' initial production is suspended until 
their cumulative production equals the field's established royalty-
suspension volume. 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 established royalty-
suspension volume is reached.
    (8) If an eligible lease is added to a field that has an established 
royalty-suspension volume as the result of an approved application for 
royalty relief submitted under 30 CFR part 203 or as the result of one 
or more eligible leases having been assigned previously to the field, 
the field's royalty-suspension volume will not change even if the added 
lease is in deeper water. If a royalty-suspension volume has been 
granted under 30 CFR part 203 that is larger than the minimum specified 
for that water depth, the added eligible lease may share in the larger 
suspension volume. The lease may receive a royalty-suspension volume 
only to the extent of its production before the cumulative production 
from all leases in the field entitled to share in the suspension volume 
equals the field's previously established royalty-suspension volume.
    (9) If a pre-Act lease(s) receives a royalty-suspension volume under 
30 CFR part 203 for a field that already has a royalty-suspension volume 
due to eligible leases, then the eligible and pre-Act leases will share 
a single royalty-suspension volume. (Pre-Act leases are OCS leases 
issued as a result of a sale held before November 28, 1995; in a water 
depth of at least 200 meters; and

[[Page 500]]

in the Gulf of Mexico west of 87 degrees, 30 minutes West longitude. See 
30 CFR part 203). The field's royalty-suspension volume will be the 
larger of the volume for the eligible leases or the volume MMS grants in 
response to the pre-Act leases' application. The suspension volume for 
each lease will be its actual production from the field until cumulative 
production from all leases in the field equals the suspension volume.
    (10) A royalty-suspension volume will continue through the end of 
the month in which cumulative production from leases in a field entitled 
to share the royalty-suspension volume reaches that volume.
    (11) If we reassign a well on an eligible lease to another field, 
the past production from that well will count toward the royalty-
suspension volume, if any, specified for the field to which it is 
reassigned. The past production will not count toward the royalty 
suspension volume, if any, for the field from which it was reassigned.
    (12) 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 this meridian will receive a royalty-suspension 
volume only for those eligible leases lying entirely west of the 
meridian.
    (13) Your 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 for another field, 
production from that new field receives a separate royalty suspension.
    (14) You must measure natural gas production subject to 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.

[45 FR 9539, Feb. 12, 1980, as amended at 45 FR 36800, May 30, 1980; 46 
FR 29689, June 2, 1981; 46 FR 35625, July 9, 1981. Redesignated at 48 FR 
1182, Jan. 11, 1983, and amended at 48 FR 24874, June 3, 1983; 56 FR 
23648, May 23, 1991; 61 FR 3804, Feb. 2, 1996; 61 FR 12027, Mar. 25, 
1996; 63 FR 2629, Jan. 16, 1998]



Sec. 260.111  Criteria for selection of bidding systems and bidding system components.

    (a) In analyzing the application of one of the bidding systems 
listed in Sec. 260.110(a) to tracts selected for any OCS lease sale, MMS 
may, in its discretion, consider the following purposes and policies, 
recognizing that each of the purposes and policies may not be 
specifically applicable to the selection process for a particular 
bidding system and tract or may present a conflict that will have to be 
resolved in the process of bidding system selection, and that the order 
of listing does not denote a ranking:
    (1) Providing fair return to the Federal Government;
    (2) Increasing competition;
    (3) Assuring competent and safe operations;
    (4) Avoiding undue speculation;
    (5) Avoiding unnecessary delays in exploration, development, and 
production;
    (6) Discovering and recovering oil and gas;
    (7) Developing new oil and gas resources in an efficient and timely 
manner;
    (8) Limiting administrative burdens on Government and industry; and
    (9) Providing an opportunity to experiment with various bidding 
systems to enable the identification of those that are the most 
appropriate for the satisfaction of the objectives of the United States 
in OCS lease sales.
    (b) In performing the analysis referred to in paragraph (a), MMS 
may, in its discretion, take into account the following in relation to 
their impact upon the purposes and policies enumerated in paragraph (a) 
of this section.
    (c) The bidding systems listed in Sec. 260.110(a) (2) and (3) shall 
be applied to not less than 20 per centum and not more than 60 per 
centum of the total area offered for leasing each year during the five-
year period commencing on September 18, 1978, unless DOI determines that 
the maximum and minimum per centum limitations set forth in this section 
are inconsistent with the purposes and policies of the OCSLA.

[45 FR 9539, Feb. 12, 1980. Redesignated and amended at 48 FR 1182, Jan. 
11, 1983]

[[Page 501]]

Subpart C [Reserved]



                        Subpart D--Joint Bidding

    Source: 45 FR 62031, Sept. 18, 1980, unless otherwise noted. 
Redesignated at 48 FR 1182, Jan. 11, 1983.



Sec. 260.301  Purpose.

    The purpose of the regulations in this subpart D is to encourage 
participation in OCS oil and gas lease sales by limiting the requirement 
for filing Statements of Production to certain joint bidders.



Sec. 260.302  Definitions.

    For purposes of this subpart D, all the terms used shall be defined 
as in 30 CFR 256.38.



Sec. 260.303  Joint bidding requirements.

    (a) Any person who submits a joint bid for any OCS oil and gas lease 
during a six-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 equivalents, and liquefied 
petroleum products, shall have filed a Statement of Production with the 
Director, MMS, in accordance with the requirements of 30 CFR 256.38. The 
Statement of Production shall state that the person filing the Statement 
is chargeable for the prior production period with an average daily 
production in excess of 1.6 million barrels of crude oil, natural gas 
equivalents, and liquefied petroleum products.
    (b) No person chargeable for the prior production period with an 
average daily production in excess of 1.6 million barrels of crude oil, 
natural gas equivalents, and liquefied petroleum products may submit a 
joint bid for any OCS oil and gas lease during the applicable six-month 
bidding period with any other person similarly chargeable. Such bids 
shall be disqualified and rejected.
    (c) No person may submit any bid during the applicable six-month 
bidding period pursuant to any agreement, the terms of which would 
result in two or more persons, each chargeable for the prior production 
period with an average daily production in excess of 1.6 million barrels 
of crude oil, natural gas equivalents, and liquefied petroleum products, 
acquiring or holding any interest in the tract for which the bid is 
submitted. Such bids shall be disqualified and rejected.



PART 270--NONDISCRIMINATION IN THE OUTER CONTINENTAL SHELF--Table of Contents




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: Sec. 604, Pub. L. 95-372, 92 Stat. 695 (43 U.S.C. 1863).

    Source: 50 FR 21048, May 22, 1985, unless otherwise noted.



Sec. 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.''



Sec. 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.



Sec. 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.

[[Page 502]]

    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.



Sec. 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.



Sec. 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.



Sec. 270.6  Process.

    Whenever a Regional Director determines on the basis of any 
information, including that which may be obtained under Sec. 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 shall proceed in 
accordance with the provisions of Secs. 250.500, 250.501, 250.502, and 
250.510 of this title.

[50 FR 21048, May 22, 1985; 64 FR 9066, Feb. 24, 1999]



Sec. 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]



PART 280--PROSPECTING FOR MINERALS OTHER THAN OIL, GAS, AND SULPHUR IN THE OUTER CONTINENTAL SHELF--Table of Contents




Sec.
280.0  Authority for information collection.
280.1  Purpose and applicability.
280.2  Definitions.
280.3  Activities requiring a permit.

[[Page 503]]

280.4  Term of permit.
280.5  Application for a prospecting or scientific research permit.
280.6  Prospecting or scientific research plan.
280.7  Obligations of persons.
280.8  Reporting.
280.9  Recordkeeping.
280.10  Environmental effects.
280.11  Notification.
280.12  Disclosure of information to the public.
280.13  Disclosure of data and information to the adjacent States.
280.14  Suspension or temporary prohibition of activities.
280.15  Cancellation or relinquishment.
280.16  Remedies and penalties.
280.17  Appeals.

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

    Source: 53 FR 25256, July 5, 1988, unless otherwise noted.



Sec. 280.0  Authority for information collection.

    The information collection requirements contained in part 280 have 
been approved by the Office of Management and Budget (OMB) under 44 
U.S.C. 3501 et seq. and assigned OMB clearance number 1010-0072. The 
information is being collected to inform the Minerals Management Service 
(MMS) of OCS minerals activities. The information will be used to ensure 
that such activities are conducted in a safe and environmentally 
responsible manner in compliance with governing laws and regulations. 
The obligation to respond is mandatory.



Sec. 280.1  Purpose and applicability.

    Section 5(a) of the Act (43 U.S.C. 1334(a)(1)) states that the 
Secretary ``* * * shall prescribe such rules and regulations * * * 
necessary to carry out * * *'' the provisions of the Act. The primary 
purpose of the regulations in this part is to prescribe policies, 
procedures, and requirements for conducting data and information-
gathering activities associated with geological and geophysical (G&G) 
prospecting and scientific research in the OCS for minerals other than 
oil, gas, and sulphur. The regulations in this part do not apply to 
activities authorized under a mineral lease. Activities authorized under 
the regulations in this part do not give rise to any rights or interests 
in any OCS mineral discovered as a result of approved prospecting or 
scientific research activities.



Sec. 280.2  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(s)--(1) That 
is used, or is scheduled to be used, as a support base for 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.
    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.
    Data means G&G facts and statistics or samples which have not been 
analyzed, processed, or interpreted.
    Director means the Director of the MMS of the U.S. Department of the 
Interior or an official authorized to act on the Director's behalf.
    Geological and geophysical (G&G) scientific research means any 
investigation conducted in the OCS for scientific research purposes 
which involves the gathering and analysis of G&G data and information 
which are made available to the public for inspection and reproduction 
at the earliest practicable time. This does not include scientific 
research related to oil, gas, and sulphur.
    Geological sample means a collected portion of the seabed, the 
subseabed, or the overlying waters acquired while conducting prospecting 
or scientific research activities.
    Governor means the Governor of a State or the person or entity 
lawfully designated to exercise the powers granted to a State Governor.
    Information means G&G data that has 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

[[Page 504]]

under section 6 of the Act and which authorizes exploration for, and 
development and production of, specific minerals or the area covered by 
that authorization.
    Material remains means physical evidence of human habitation, 
occupation, use, or activity, including the site, location, or context 
in which such evidence is situated.
    Minerals has the same meaning as the term is defined in section 2(q) 
of the Act.
    National Environmental Policy Act (NEPA) means the National 
Environmental Policy Act of 1969 (42 U.S.C. 4321 et seq.).
    OCS minerals means any mineral found on or below the surface of the 
seabed but does not include oil, gas, or sulphur.
    Of 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.
    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.
    Permit means the contract or agreement, other than a lease, approved 
pursuant to this part under which a person acquires the right to conduct 
prospecting or scientific research activities.
    Permittee means the person authorized by a permit issued pursuant to 
this part to conduct prospecting or scientific research activities in 
the OCS.
    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; and 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.
    Prospecting activities means the gathering of any G&G data and 
information for the purpose of determining the feasibility of commercial 
recovery, which has as its objective the establishment and documentation 
of the nature, shape, concentration, location, and tenor of an OCS 
mineral resource. Such activities shall include (1) geophysical surveys 
where magnetic, gravity, seismic, or other systems are used to detect or 
imply the presence of minerals; and (2) the gathering through drilling 
or other means of geological samples which could be used for the purpose 
of discovering, characterizing, or evaluating OCS mineral deposits. 
Prospecting activities do not include G&G scientific research.
    Secretary means the Secretary of the Interior or an official 
authorized to act on the Secretary's behalf.
    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.

[53 FR 25256, July 5, 1988, as amended at 59 FR 53094, Oct. 21, 1994]



Sec. 280.3  Activities requiring a permit.

    (a) No prospecting activities shall be conducted in the OCS without 
a permit approved by the Director pursuant to this part, unless such 
activities are being conducted pursuant to authority contained in a 
lease issued or maintained under part 256 or part 281 of this title or 
unless such activities are conducted by a Federal Agency.
    (b) No person may conduct G&G scientific research activities in the 
OCS without a permit approved by the Director pursuant to this part if 
the proposed activities include either: (1) The drilling of a borehole 
to a depth greater than 300 feet below the seafloor; or (2) the use of 
solid or liquid explosives.

[[Page 505]]

    (c) Any person may conduct G&G scientific research in the OCS 
without obtaining a permit pursuant to this part if--
    (1) The activities will not interfere with or endanger operations 
under any lease or right-of-way maintained or issued pursuant to the 
Act;
    (2) The activities will not be unduly harmful to aquatic life in the 
area; result in pollution; create hazardous or unsafe conditions; 
unreasonably interfere with other uses of the area; or disturb any site, 
structure, or object of historical or archaeological significance; and
    (3) The person conducting the activities or operating the vessel 
from which the activities are to be conducted has consulted and 
coordinated the conduct of those activities with any other users of the 
area.
    (d) The Director may orally approve plan revisions or issue 
emergency permits to accommodate unforeseen or special circumstances. 
Oral approvals given for a written application shall be followed with a 
written confirmation by MMS. In the event an oral approval is given in 
response to an oral request, the applicant shall confirm the oral 
request in writing within 72 hours of the approval.



Sec. 280.4  Term of permit.

    Permits approved under this part shall be granted for a term not to 
exceed 3 years. The Director may extend the term of a permit for an 
additional period(s) of time not to exceed a total of 2 years when the 
Director determines that the additional time is appropriate based upon a 
showing of good cause by the permittee.



Sec. 280.5  Application for a prospecting or scientific research permit.

    (a) An application for a prospecting or scientific research permit 
shall be submitted to the Director at least 60 days prior to the date 
proposed as the startup date for activities in the permit area.
    (b)(1) An application for a prospecting permit shall be submitted in 
a form and manner approved by the Director. Three copies of each 
application shall be submitted and shall include--
    (i) The name, address, and nationality of the person(s) submitting 
the application;
    (ii) The name, address, and telephone number of the person(s) 
directly responsible for conducting the activities proposed;
    (iii) A description and a map of the area(s) covered by the 
application;
    (iv) The period of time to be covered by the primary term of the 
permit not to exceed 3 years;
    (v) A narrative description in nonproprietary terms of the 
activities to be conducted, such as mapping, geophysical surveying, 
drilling, bottom sampling, and dredging;
    (vi) A detailed description and schedule giving the estimated 
starting and completion dates for the proposed activities that are to be 
authorized under the permit; and
    (vii) A prospecting plan.
    (2) An applicant for a prospecting permit shall indicate which data 
and information included in the application and plan the applicant 
considers proprietary.
    (c) Upon application submitted by a permittee pursuant to this 
section, the Director may approve the conversion of a permit issued 
under part 251 of this title to a permit issued under this part. A 
permit issued under part 251, which is converted to a permit issued 
under this part, shall be subject to all the requirements of this part.
    (d) An application for a permit to conduct scientific research 
activities shall be submitted in a form approved by the Director. The 
application should be signed by an officer of the organization proposing 
to carry out the activity and shall state--
    (1) The name of the person conducting the proposed research;
    (2) The type of research activity and manner in which it will be 
conducted;
    (3) The location designated on a map, plat, or chart where the 
research activity will be conducted;
    (4) A schedule indicating the starting and completion dates for each 
proposed scientific research activity;
    (5) The proposed time and manner in which the information and data 
resulting from the research will be made available to the public for 
inspection

[[Page 506]]

and reproduction, such time being the earliest practicable time;
    (6) An agreement that the information and data resulting from the 
scientific research activity will not be sold or withheld for exclusive 
use;
    (7) The name, registry number, registered owner, and port of 
registry of vessels used in the operation; and
    (8) A scientific research plan.
    (e) Within 30 days following the receipt of an application for a 
permit and the accompanying plan which does not require preparation of 
an environmental analysis the Director shall--
    (1) Approve the application and plan;
    (2) Require the applicant to modify the application and/or plan; or
    (3) Disapprove the application and plan. If the Director disapproves 
an application and plan, the statement of rejection shall give the 
reasons for the disapproval and shall advise the applicant of the 
changes needed to obtain approval.



Sec. 280.6  Prospecting or scientific research plan.

    (a) The applicant shall submit a plan with its application for a 
prospecting or scientific research permit. The plan shall include--
    (1) Identification of the mineral(s) or material(s) of primary 
interest, if appropriate;
    (2) A detailed description of the activities to be conducted;
    (3) The type(s) of equipment to be used with special attention to 
safety and pollution prevention and control features and the name, 
registration, and mobile communication system of vessel(s);
    (4) Maps showing location of proposed activities including drill 
holes, grab or basket samples, anticipated depth of penetration of drill 
holes, water depth, and location of proposed survey grids for each 
surveying method which is to be employed;
    (5) A schedule indicating the starting and completion dates for each 
proposed activity;
    (6) Anticipated environmental consequences of each proposed 
activity;
    (7) Mitigation measures to be used to avoid or minimize adverse 
environmental impacts of proposed activities;
    (8) For any activities which are to occur in an environmentally 
sensitive area, a plan for monitoring the effects of the activities on 
the environment;
    (9) Any known archaeological resources in the area of the proposed 
activities; and
    (10) Description of any potential conflicts with other uses or users 
in the permit area.
    (b) If the penetration of one or more proposed drill holes will 
exceed 300 feet, the Director may require a drilling plan to be included 
as part of the plan before a permit is issued.
    (c) If all needed information is not available at the time the plan 
is submitted, a plan shall indicate when the needed information will be 
obtained and submitted. In such a case, depending on the significance of 
the missing information, the Director may disapprove the plan, approve 
the plan based on the information submitted, or approve the plan with a 
specific condition that certain specified activities are not authorized 
and shall not be conducted until additional information is obtained and 
submitted for evaluation, and the Director gives specific approval to 
proceed with those activities.



Sec. 280.7  Obligations of persons.

    (a) Activities authorized under a prospecting or scientific research 
permit issued under this part or research authorized pursuant to the 
provisions of Sec. 280.5(c) of this part shall be conducted so as not to 
create conditions which will pose an unreasonable risk of--
    (1) Interference with, or endangerment of, operations under any 
lease or permit issued or maintained pursuant to the Act;
    (2) Serious, irreparable, or immediate harm or damage to life 
(including fish and other aquatic life) or to the marine, coastal, or 
human environment;
    (3) Serious, irreparable, or immediate harm or damage to property or 
to any mineral (in areas leased or not leased);
    (4) Pollution;
    (5) Disturbance of archaeological resources;
    (6) Hazardous or unsafe conditions; or
    (7) Interference with or serious, irreparable, or immediate harm to 
other uses of the area.

[[Page 507]]

    (b) The permittee or scientific researcher shall allow the Director 
to be present on any cruise.
    (c) The permittee shall notify and obtain the prior approval of the 
Director before a substantial change from the approved plan is 
initiated.



Sec. 280.8  Reporting.

    (a) The permittee shall submit a status report to the Director 
within 30 days of the close of each calendar quarter or more frequently 
if requested by the Director. The report shall include a summary of the 
prospecting or scientific research activities conducted prior to the end 
of the reporting period and the results obtained. The last quarterly 
report may be combined with the final report if the final report is 
submitted within 30 days after the end of the last quarter in which 
permitted activity occurs. Each permittee shall submit to the Director a 
final report of activities conducted under the permit within 6 months 
after expiration of the permit or after the completion of prospecting or 
scientific research activities, or 60 days prior to a planned lease 
offering when prospecting or scientific research activities are within 
the planned leasing area, whichever is sooner, provided that no report 
shall be required less than 30 days after completion of permitted 
activities. The report shall include--
    (1) A description of the work performed;
    (2) Charts, maps, or plats depicting the area and blocks in which 
any activities were conducted specifically, identifying the lines of 
geophysical traverses and/or the locations where geological activity was 
conducted;
    (3) The dates on which the actual activities were performed;
    (4) A narrative summary of any mineral occurrences encountered 
including location, environmental features, and the nature and degree of 
adverse effects, if any, of the permitted activities on the environment, 
aquatic life, archaeological resources, or other uses of the area in 
which the activities were conducted;
    (5) A report of the results of the environmental monitoring required 
in Sec. 280.6(a)(8) of this part; and
    (6) Such other descriptions of the activities conducted as may be 
specified by the Director.
    (b) All persons shall immediately notify the Director of all serious 
accidents, any death or serious injury, or fire or explosion connected 
with any activity conducted pursuant to this part.



Sec. 280.9  Recordkeeping.

    (a) Any permittee who acquires rock and mineral samples under a 
permit shall keep for 1 year after submittal of the final report a 
representative split of each geological sample and a quarter 
longitudinal segment of each core which shall be available for 
inspection at the convenience of the Director who may cut such core and 
geological samples for retention by MMS.
    (b) Any permittee who acquires G&G data and information under a 
permit shall keep the data and information available for 3 years after 
submittal of the final report. The data and information shall be 
available for inspection and copying at a location within the 
appropriate OCS Region or at another location approved by the Director. 
The records shall include environmental data and information; G&G data 
and information; drill logs; analyses of cores, cuttings, and samples; 
and maps and navigation tapes showing the location where samples were 
taken and test drilling conducted.



Sec. 280.10  Environmental effects.

    The potential of proposed prospecting or scientific research 
activities for adverse impact on the environment will be evaluated by 
MMS to determine the need for mitigation measures. The MMS anticipates 
that activities of the type listed below typically will not cause 
significant environmental impact and, in accordance with 516 DM 6, 
Appendix 10 to the Departmental Manual, 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;

[[Page 508]]

    (c) Mineral sampling of a limited nature such as that using either 
test drillholes or cores to less than 300 feet below the seafloor;
    (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 mineral assaying and analysis; and
    (j) Placement of positioning systems, including bottom transponders 
and surface and subsurface buoys reported in Notices to Mariners.



Sec. 280.11  Notification.

    (a) The Governor(s) of adjacent State(s) shall be notified by the 
Director with a copy of the application for a permit with the 
accompanying plan immediately upon the submission of an application for 
approval.
    (b) In cases where an environmental assessment is to be prepared, 
the Director will invite the Governor(s) of adjacent States(s) to review 
and provide comments regarding the proposed activities. The Director's 
invitation to provide comments shall allow the Governor a specified 
period of time to comment.
    (c) The Director shall notify Federal Agencies, as appropriate, with 
a copy of the application for a permit with the accompanying plan 
immediately upon the submission of the application for approval.



Sec. 280.12  Disclosure of 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.
    (b) For geological data, information, and samples and geophysical 
information submitted under a permit and retained by MMS, the Director 
shall make such data, information, and samples available to the public 
25 years after the date of submission of the data and information or 
such earlier time as may be agreed to by the permittee who provides the 
data or information. Geophysical data submitted under a permit and 
retained by MMS shall be made available to the public by the Director 50 
years after the date of submission to MMS unless an earlier date is 
agreed to by the permittee who submits the data.
    (c) The Director reserves the right to disclose any data, 
information, or samples submitted by a permittee to an independent 
contractor or agent for the purpose of reproducing, processing, 
reprocessing, or interpreting the data or information. Such contractor 
or agent shall be subject to the same limitations on disclosure of data, 
information, and samples as those applicable to the Director under 
paragraph (b) of this section.



Sec. 280.13  Disclosure of data and information to the adjacent States.

    (a) Proprietary data, information, and samples submitted to MMS by 
permittees shall be made available to 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 the 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;

[[Page 509]]

    (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 and information and 
samples; and
    (4) The materials containing the proprietary data, information, and 
samples shall remain the property of the United States.
    (c) The data, information, and samples available to the State(s) 
pursuant to an agreement shall be related to leased lands.
    (d) The materials containing the proprietary data, information, and 
samples shall be returned to MMS when they are no longer needed by the 
State or when requested by the Director.



Sec. 280.14  Suspension or temporary prohibition of activities.

    The Director may suspend or temporarily prohibit the conduct of G&G 
prospecting or scientific research activities by notifying the person 
conducting the activity, either orally or in writing, when the Director 
determines that there is a threat of serious, irreparable, or immediate 
harm or damage to life (including fish and other aquatic life), 
property, any mineral (in areas leased or not leased), the national 
security or defense, or the marine, coastal, or human environment; or 
there is a failure to comply with a provision of the Act or of any 
applicable law, the provisions of the permit, or provisions of these and 
other applicable regulations. Such suspension or temporary prohibition 
shall be effective immediately upon receipt of the notice. Suspensions 
or temporary prohibitions issued orally shall be followed by a written 
notice confirming the action, and all written notices will be sent by 
certified or registered mail. A suspension or temporary prohibition 
shall remain in effect until the basis for the suspension or temporary 
prohibition has been corrected to the satisfaction of the Director.



Sec. 280.15  Cancellation or relinquishment.

    The Director may cancel or a permittee may relinquish, in whole or 
in part, a permit to conduct prospecting or scientific research 
activities at any time by sending a notice of cancellation or a notice 
of relinquishment. Such notices shall state the reason for the 
cancellation or relinquishment and shall be sent by certified or 
registered mail to the other party at least 30 days in advance of the 
date that the cancellation or relinquishment will be effective.



Sec. 280.16  Remedies and penalties.

    Persons conducting activities in the OCS pursuant to this part shall 
be subject to the remedies and penalties provisions of section 24 of the 
Act and the applicable civil penalty procedures contained in part 250 of 
this title for noncompliance with any provision of the Act, permit, 
regulation, or order issued under the Act. The remedies or penalties 
prescribed in this section shall be in addition to any other penalty 
afforded by any other law or regulation.



Sec. 280.17  Appeals.

    Orders or decisions issued under the regulations in this part may be 
appealed as provided in part 290 of this title.



PART 281--LEASING OF MINERALS OTHER THAN OIL, GAS, AND SULPHUR IN THE OUTER CONTINENTAL SHELF--Table of Contents




                           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.

[[Page 510]]

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. 1331 et seq.

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



                           Subpart A--General



Sec. 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. The obligation to respond is 
mandatory.



Sec. 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.



Sec. 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)).



Sec. 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

[[Page 511]]

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.



Sec. 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.



Sec. 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.



Sec. 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 
Sec. 281.21 of this part.



Sec. 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).

[[Page 512]]



Sec. 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 uner 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.



Sec. 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



Sec. 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.



Sec. 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 Sec. 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

[[Page 513]]

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]



Sec. 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).



Sec. 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 Sec. 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

[[Page 514]]

tracts will be considered in the environmental analysis conducted for 
the proposed lease offering.



Sec. 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.



Sec. 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 Sec. 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.



Sec. 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.



Sec. 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.

[[Page 515]]

    (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 Sec. 281.33.



Sec. 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.



Sec. 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,

[[Page 516]]

shall be presented to MMS at the lease sale prior to the offering of an 
oral bid.



Sec. 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 Sec. 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 Sec. 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.



Sec. 281.22  Lease form.

    The OCS mineral leases shall be issued on the lease form prescribed 
by the Secretary in the leasing notice.



Sec. 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



Sec. 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

[[Page 517]]

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 Payor Information Form 
(MMS-4030) in accordance with Sec. 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 Sec. 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 information forms 
and maintain auditable records in accordance with the following Royalty 
Management regulations of this title:

Section 210.200--Required recordkeeping.
Section 210.201--Solid minerals payor information form.
Section 210.202--Report of sales and royalty remittance--solid minerals.
Section 210.203--Special forms and reports.
Section 212.200--Maintenance of and access to records.
Section 217.250--Audits.
Section 218.40--Assessments for incorrect or late reports and failure to 
          report.
Section 218.50--Timing of payment.
Section 218.51--Method of payment.
Section 218.52--Designated payor.
Section 218.56--Definitions.
Section 218.150--Royalties, net profit shares, and rental payments.
Section 218.151--Rentals.
Section 218.155--Method of payment.
Section 218.202--Late payment or underpayment charges.
Section 241.20--Civil penalties authorized by statutes other than the 
          Federal Oil and Gas Royalty Management Act of 1982.



Sec. 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 Sec. 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.

[[Page 518]]

    (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.



Sec. 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.



Sec. 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.



Sec. 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 
Sec. 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.



Sec. 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 
Sec. 281.30 of this part, paragraph (a) of this section, and Sec. 281.32 
of this part.



Sec. 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

[[Page 519]]

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.



Sec. 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 
Sec. 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



Sec. 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.

[[Page 520]]

    (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.



Sec. 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 
Sec. 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 
Sec. 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.



Sec. 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

[[Page 521]]

earning the continuation of the lease in effect.



Sec. 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



Sec. 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.



Sec. 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

[[Page 522]]

    (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).



PART 282--OPERATIONS IN THE OUTER CONTINENTAL SHELF FOR MINERALS OTHER THAN OIL, GAS, AND SULPHUR--Table of Contents




                           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. 1331 et seq.

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



                           Subpart A--General



Sec. 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

[[Page 523]]

regulations. The requirement to respond is mandatory.



Sec. 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.



Sec. 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.



Sec. 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

[[Page 524]]

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.



Sec. 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

[[Page 525]]

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).



Sec. 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

[[Page 526]]

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.



Sec. 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.



Sec. 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



Sec. 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.



Sec. 282.11  Director's authority.

    (a) In the exercise of jurisdiction under Sec. 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:

[[Page 527]]

    (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.



Sec. 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.

[[Page 528]]

    (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 Sec. 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 Sec. 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 Sec. 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

[[Page 529]]

    (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 
Sec. 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.



Sec. 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.

[[Page 530]]

    (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

[[Page 531]]

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 
Sec. 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 
Sec. 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.



Sec. 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

[[Page 532]]

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)).



Sec. 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,

[[Page 533]]

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



Sec. 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

[[Page 534]]

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 Sec. 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.



Sec. 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

[[Page 535]]

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.



Sec. 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 Sec. 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

[[Page 536]]

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.



Sec. 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 Sec. 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);

[[Page 537]]

    (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.



Sec. 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,

[[Page 538]]

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 Sec. 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.



Sec. 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 
Secs. 282.21, 282.22, 282.23, and 282.24 of this part.



Sec. 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 Sec. 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.



Sec. 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

[[Page 539]]

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.

[[Page 540]]

    (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 Sec. 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.



Sec. 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

[[Page 541]]

Sec. Sec. 250.194, 250.203(b)(19), 250.204(b)(12), 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]



Sec. 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

[[Page 542]]

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 Sec. 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

[[Page 543]]

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.



Sec. 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.



Sec. 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



Sec. 282.40  Bonds.

    (a) Pursuant to the requirements for a bond in Sec. 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

[[Page 544]]

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 
Sec. 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 four areas:
    (1) The Gulf of Mexico;
    (2) The area offshore the Pacific Coast States of California, 
Oregon,Washington, and Hawaii;
    (3) The area offshore the coast of Alaska; and
    (4) The area offshore the Atlantic coast.
    (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]



Sec. 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.



Sec. 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 Sec. 281.26 of this title.



                           Subpart E--Appeals



Sec. 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]

[[Page 545]]





                          SUBCHAPTER C--APPEALS





PART 290--APPEAL PROCEDURES--Table of Contents




        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--Appeals of Royalty Management Program and Delegated State 
                                 Orders

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?
290.111  How will MMS and delegated States serve official 
          correspondence?

    Authority: 5 U.S.C. 301 et seq.; 43 U.S.C. 1331 et seq.

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



        Subpart A--Offshore Minerals Management Appeal Procedures



Sec. 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.



Sec. 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.



Sec. 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.



Sec. 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

[[Page 546]]

Electronic Funds Transfer (EFT) for these payments.



Sec. 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).



Sec. 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 Sec. 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 Sec. 290.3.



Sec. 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 Sec. 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.



Sec. 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--Appeals of Royalty Management Program and Delegated States 
                                 Orders



Sec. 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 MMS Royalty 
Management Program (RMP) and the payment of royalties and other payments 
due under leases subject to this subpart.



Sec. 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.



Sec. 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

[[Page 547]]

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 RMP, or a delegated State that contains 
mandatory 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.



Sec. 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 Sec. 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 Sec. 290.106.



Sec. 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.



Sec. 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

[[Page 548]]

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.



Sec. 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 
Sec. 290.103, you may join in that appeal within 30 days after you 
receive your designee's Notice of Appeal under Sec. 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.



Sec. 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.



Sec. 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.

[[Page 549]]



Sec. 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.



Sec. 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]



Sec. 290.111  How will MMS and delegated States serve official correspondence?

    (a) Method of service. The Royalty Management Program (RMP) or a 
delegated State will serve official correspondence by sending the 
document by certified or registered mail, return receipt requested, to 
the addressee of record established in paragraph (b) of this section. 
Instead of certified or registered mail, RMP or a delegated State may 
deliver the document personally to the addressee of record and obtain a 
signature acknowledging the addressee's receipt of the document. 
Official correspondence includes all orders that are appealable under 
this subpart.
    (b) Addressee of record. (1) The addressee of record for 
administrative correspondence for refiners participating in the 
Government's Royalty-in-Kind (RIK) Program is the position title, 
department name and address, or individual name and address identified 
in the executed royalty oil sale contract. The refiner/purchaser may 
identify, in writing, a different position title, department name and 
address, or individual name and address for billing purposes. The 
refiner must notify MMS, in writing, of all addressee changes.
    (2) The addressee of record for serving official correspondence on 
anyone required to report energy and mineral resources removed from 
Federal and Indian leases to the RMP Production Accounting and Auditing 
System is the most recent position title, department name and address, 
or individual name and address that RMP has in its records for the 
reporter/payor. The reporter/payor is responsible for notifying RMP, in 
writing, of any addressee changes.
    (3) The addressee of record for serving official correspondence 
concerning

[[Page 550]]

onshore Federal leases is the current lessee of record with the Bureau 
of Land Management. For Indian leases, the addressee of record is the 
current lessee of record with the Bureau of Indian Affairs. For offshore 
leases, the addressee of record is the current lessee of record with the 
MMS Offshore Minerals Management Program. The lessee is responsible for 
notifying the appropriate Government office of any addressee changes.
    (4) The addressee of record for serving official correspondence in 
connection with reviews and audits of payor records is the position 
title, department name and address, or individual name and address 
designated, in writing, by the company at the initiation of the audit, 
or the most recent addressee that was specified, in writing, by the 
payor.
    (5) The addressee of record for serving official correspondence 
relating to reporting on the ``Report of Sales and Royalty Remittance'' 
(Form MMS-2014) is the most recent position title, department name and 
address, or individual name and address specified, in writing, by the 
payor. The payor is responsible for notifying RMP, in writing, of any 
addressee changes.
    (6) The addressee of record for serving official correspondence in 
connection with remittances pertaining to rental and bonuses from 
nonproducing Federal leases is the most recent position title, 
department name and address, or individual name and address maintained 
in RMP records. The payor is responsible for notifying RMP, in writing, 
of any addressee changes.
    (7) The addressee of record for serving official correspondence 
including orders, demands, invoices, or decisions, and other actions 
identified with payors reporting to the RMP Auditing and Financial 
System not identified above is the position title, department name and 
address or individual name and address for the payor identified on the 
most recent Payor Confirmation Report (Report No. RPI140R1) of a Payor 
Information Form (PIF) (Form MMS-4025 or Form MMS-4030) returned by RMP 
to the payor for the Federal or Indian lease (see 30 CFR 210.51 and 
210.201).
    (8) If correspondence applies to more than one category identified 
in paragraphs (b)(1) through (7) of this section, MMS may serve the 
official correspondence in accordance with the requirements of any one 
paragraph.
    (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 established under paragraph 
(b) of this section. A receipt signed by any person at that address is 
evidence of service. If official correspondence is served both 
personally and by registered or certified mail, the date of service is 
the earlier of the two dates, if they are different.
    (d) Constructive service. (1) If delivery cannot be made after 
reasonable effort at the address of record established under paragraph 
(b) of this section, MMS deems official correspondence as constructively 
served 7 days after the date that the document is mailed.
    (2) This provision covers such situations as nondelivery because the 
addressee has moved without filing a forwarding address, the forwarding 
order had expired, delivery was expressly refused, or the document was 
unclaimed where the attempt to deliver is substantiated by U.S. Postal 
Service authorities.

[64 FR 50753, Sept. 20, 1999]

[[Page 551]]



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.................         553

[[Page 553]]



PART 301--PROCEDURES UNDER SURFACE MINING CONTROL AND RECLAMATION ACT OF 1977--Table of Contents




    Authority: Sec. 201, Pub. L. 95-87, 91 Stat. 445, 30 U.S.C. 1201 et 
seq.



Sec. 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]

[[Page 555]]



        CHAPTER IV--GEOLOGICAL SURVEY, DEPARTMENT OF THE INTERIOR




  --------------------------------------------------------------------
Part                                                                Page
401             State Water Research Institute Program......         557
402             Water-Resources Research Program and the 
                    Water-Resources Technology Development 
                    Program.................................         562

[[Page 557]]



PART 401--STATE WATER RESEARCH INSTITUTE PROGRAM--Table of Contents




                           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



Sec. 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.



Sec. 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.



Sec. 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]



Sec. 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.

[[Page 558]]

    (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]



Sec. 401.5  [Reserved]



        Subpart B--Designation of Institutes; Institute Programs



Sec. 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 Sec. 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 Sec. 401.26.

[50 FR 23114, May 31, 1985, as amended at 58 FR 27204, May 7, 1993]



Sec. 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;

[[Page 559]]

    (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.



Secs. 401.8-401.10  [Reserved]



            Subpart C--Application and Management Procedures



Sec. 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

[[Page 560]]

    (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]



Sec. 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]



Secs. 401.13-401.18  [Reserved]



                          Subpart D--Reporting



Sec. 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.

[[Page 561]]

    (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.



Secs. 401.20-401.25  [Reserved]



                          Subpart E--Evaluation



Sec. 401.26  Evaluation of institutes.

    (a) Within 2 years of the date of its certification according to the 
provisions of Sec. 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

[[Page 562]]

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]



PART 402--WATER-RESOURCES RESEARCH PROGRAM AND THE WATER-RESOURCES TECHNOLOGY DEVELOPMENT PROGRAM--Table of Contents




                           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.

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

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



                           Subpart A--General



Sec. 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.



Sec. 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.



Sec. 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.



Sec. 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

[[Page 563]]

oversight responsibilities and provide dissemination of technical 
information.



Sec. 402.5  [Reserved]



           Subpart B--Description of Water-Resources Programs



Sec. 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.



Sec. 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 Sec. 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.



Secs. 402.8-402.9  [Reserved]



      Subpart C--Application, Evaluation, and Management Procedures



Sec. 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

[[Page 564]]

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.



Sec. 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 
Sec. 402.11(b). Program announcements and applications will be governed 
by the same procedures provided in Sec. 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 Sec. 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.



Sec. 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.



Sec. 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

[[Page 565]]

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.



Sec. 402.14  [Reserved]



                          Subpart D--Reporting



Sec. 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.

[[Page 567]]



                      CHAPTER VI--BUREAU OF MINES,






                       DEPARTMENT OF THE INTERIOR




  --------------------------------------------------------------------

                      SUBCHAPTER A--HELIUM AND COAL
Part                                                                Page
601             Sales of helium by and rental of containers 
                    from the Bureau of Mines................         569
                       SUBCHAPTERS B-L [RESERVED]
  SUBCHAPTER M--RULES AND REGULATIONS FOR THE ADMINISTRATION OF GRANTS
652             Mining and Mineral Resources Research 
                    Institute Program.......................         573
653-699         [Reserved]

[[Page 569]]





                      SUBCHAPTER A--HELIUM AND COAL





PART 601--SALES OF HELIUM BY AND RENTAL OF CONTAINERS FROM THE BUREAU OF MINES--Table of Contents




Sec.
601.1  Purpose.
601.2  Definitions.
601.3  Contract application forms and procedures.
601.4  [Reserved]
601.5  Schedule of prices and charges.
601.6  Purchase price of helium.
601.7  Service charges.
601.8  Settlements under existing contracts.
601.9  Shipping containers.
601.10  [Reserved]
601.11  Applicability to Federal Agencies.

    Authority: Pub. L. 86-777, approved Sept. 13, 1960, 74 Stat. 918 (50 
U.S.C. 167-167n).

    Source: 46 FR 37506, July 21, 1981, unless otherwise noted.



Sec. 601.1  Purpose.

    The purpose of this part 601 is to establish procedures governing 
the sale of helium and related services by the Bureau of Mines, and the 
rental of helium containers from the Bureau of Mines.



Sec. 601.2  Definitions.

    (a) Act means the Helium Act, Pub. L. 86-777, approved September 13, 
1960 (74 Stat. 918; 50 U.S.C. 167-167n).
    (b) [Reserved]
    (c) Helium plant means a facility operated by or for the U.S. Bureau 
of Mines for the production, purification, repurification, or shipment 
of helium.
    (d) Bureau means the Bureau of Mines of the Department of the 
Interior.
    (e) Purchaser means any individual, corporation, partnership, firm, 
association, trust, estate, public or private institution, state or 
political subdivision thereof, having a new (after revision of this 
part) helium purchase contract with the Bureau, and any agency of the 
U.S. Government, purchasing helium from the Bureau or using helium 
containers rented from the Bureau.
    (f) Grade-A helium means the grade of helium produced at the 
Bureau's helium plants, and is 99.995 percent pure helium, or better by 
volume.
    (g) Standard cubic foot (scf) is a

1-cubic foot volume of Grade-A helium measured at a pressure of 14.7 
pounds per square inch absolute and a temperature of 70  deg.Fahrenheit.
    (h) Cylinder means a standard-type cylinder of approximately 1.5 
cubic feet internal volume, designed for a filling pressure of 1,800 
pounds per square inch gage or more, which will stand vertically without 
external support with the center of the valve outlet not less than 50\1/
2\ inches nor more than 58\1/2\ inches above the floor, equipped with a 
standard-type cylinder valve, safety relief device, and valve-protective 
cap, or a similar cylinder acceptable to the Bureau as a standard type.
    (i) Valve means a standard-type cylinder valve acceptable to the 
Bureau of Mines having a valve outlet conforming to Specification No. 
580 or No. 350 as described by the latest edition of Compressed Gas 
Association, Inc., Pamphlet V-1, ANSI B57.1-1977; Provided, That at the 
Bureau's option, valves with outlets conforming to other specifications 
may be accepted as alternate standards.
    (j) Tank car means a railroad car permanently equipped with multiple 
tubes manufactured in accordance with 49 CFR 179.500.
    (k) Tube trailer means a road-type semitrailer without motive power 
permanently equipped with multiple tubes manufactured in accordance with 
49 CFR 178.36, 178.37, or 178.45.
    (l) Tube module means one or more seamless steel tubes, manufactured 
in accordance with 49 CFR 179.500, that by means of a framework are 
joined together to form a unit. Valves may be manifolded.
    (m) Liquid helium trailer means a special road-type semitrailer 
without motive power, equipped with a vacuum-jacketed container suitable 
for transporting 1,000 U.S. gallons or more of liquid helium. The 
container may be separable or an integral part of the chassis and 
dependent upon design, may or may not require a Department of 
Transportation (DOT) special permit for transporting.

[[Page 570]]

    (n) Liquid helium dewar (dewar) means a portable or skid-mounted, 
vacuum-jacketed container suitable for shipping less than 1,000 U.S. 
gallons of liquid helium.
    (o) Schedule of Prices and Charges (Schedule) means a listing of 
prices and charges for products and services provided under contract 
pursuant to this part.
    (p) Federal Agency is any department, independent establishment, 
commission, administration, foundation, authority, board, or bureau of 
the U.S. Government, or any corporation owned, controlled, or in which 
the U.S. Government has a proprietary interest, as these terms are 
defined in 5 U.S.C. 101-05; 5 U.S.C. 551(1); 5 U.S.C. 552(e); or in 18 
U.S.C. 6, but does not include Federal agency contractors.
    (q) Contracting officer is the person executing a contract on behalf 
of the Government, and includes any duly appointed successor.



Sec. 601.3  Contract application forms and procedures.

    (a) Any prospective helium purchaser may make application to the 
Bureau to become a purchaser of helium, and, if desired, rent containers 
from the bureau and, upon meeting the requirements of this part and upon 
execution of a purchase (and container rental) contract with the Bureau, 
may purchase helium (and rent containers) from the Bureau. To be 
eligible, a prospective purchaser must: demonstrate adequate financial 
resources to pay for helium and helium-related services in advance, hold 
a certificate of competency and/or a determination of eligibility from 
the Small Business Administration if the prospective purchaser is a 
small business concern and is determined to be nonresponsible and/or 
ineligible by the contracting officer, and be otherwise qualified and 
eligible to enter into a Bureau contract under applicable laws and 
regulations.
    (b) The information collection requirement contained in this 
paragraph has been approved by the Office of Management and Budget under 
44 U.S.C. 3507 and assigned clearance number 1032-0111. The information 
is being collected to identify firms desiring to enter into a contract. 
This information will be used to complete contract documents and 
establish cash advance required. The obligation to respond is required 
to obtain a benefit.
    (c) The contract shall include, among other things, duties and 
responsibilities of the parties, definitions, term, minimum contract 
volume, and other conditions, such as advance payments, deposits, surety 
bonds, repurchase rights of the Government, liabilities, reservations 
with respect to sales and deliveries, power of inspection, notification 
to repurchasers, violations and penalties, cancellation and assignment 
of contract, termination, general provisions, and standard provisions.
    (d) Application forms are available upon written request from 
Division of Helium Operations, 1100 S. Fillmore St., Amarillo, Texas 
79101. Applicable contract form(s) and Schedule will be included for 
examination by the prospective purchaser.
    (e) Upon approval by the Contracting Officer of the returned 
application, the contract will become effective when executed by both 
parties.



Sec. 601.4  [Reserved]



Sec. 601.5  Schedule of prices and charges.

    (a) The Schedule of Prices and Charges (Schedule) is published by 
the Bureau of Mines, Division of Helium Operations, and is periodically 
updated. The Schedule is available upon request from the Division of 
Helium Operations, 1100 S. Fillmore St., Amarillo, Texas 79101, 
telephone 806-376-2638 or FTS 735-1638. The Schedule shows prices and 
charges for helium, ordinary related services, use or rental of Bureau-
owned helium containers or equipment, cash advance, and deposit 
required, and bonds and/or insurance to guarantee return of containers.
    (b) Terms and conditions under which products and services can be 
acquired under contract pursuant to this part are shown in appendix 1 to 
the Schedule. The terms and conditions are reviewed at least annually, 
and are revised as required.
    (c) Revisions to the Schedule are determined at least annually by 
the Division of Helium Operations in accordance with Office of 
Management and

[[Page 571]]

Budget (OMB) Circular No. A-25, as revised. In no case will a revised 
Schedule become effective in less than 30 days after date of 
distribution to all Bureau helium customers known at the time of 
distribution.



Sec. 601.6  Purchase price of helium.

    (a) The purchase price of Grade-A helium shipped f.o.b. origin shall 
be the price stated in the Schedule that is in effect on the date the 
helium is shipped from the helium plant.
    (b) [Reserved]
    (c) The purchase price of Grade-A helium shipped f.o.b. destination 
shall be the price stated in the Schedule that is in effect on the date 
the helium is shipped from the helium plant plus any service charges, 
container charges, transportation charges, and other charges incurred in 
making such delivery. Delivery of helium f.o.b. destination is made only 
in Bureau-furnished containers.



Sec. 601.7  Service charges.

    In addition to the purchase price of helium, the following charges 
for services and use of equipment rented from the Bureau shall be paid 
by the purchaser.
    (a) For filling containers. The charge for filling helium containers 
shall be as shown in the Schedule that is in effect on the date the 
helium is shipped from the helium plant.
    (b) For ordinary work performed on containers supplied by the 
purchaser and for ordinary services performed in connection with 
shipment of helium from a helium plant. The charge for ordinary work 
shall be as shown in the Schedule that is in effect on the date the work 
is performed.
    (c) For extraordinary expenses.Such expenses incurred in connection 
with any contract or delivery for which prices are not stated in the 
effective Schedule including, but not limited to, costs of work on 
purchaser's containers, filling, servicing, and rental of containers of 
types other than those stated in the effective Schedule, purifying 
helium beyond normal plant purity, (delete ``liquefying helium'') 
analytical services, shipment of helium from other than a helium plant 
selected by the Bureau, and unusual handling, transportation, and 
communications, may be determined by the Bureau and charged to the 
purchaser as they arise on the basis of the cost of rendering the 
services, making due allowance for contingencies, overhead expense, and 
commercial common-carrier rates.
    (d) For use of helium containers supplied by the Bureau. The charge 
for use of each Bureau-supplied container shall be as shown in the 
Schedule in effect on the date of shipment from a helium plant.



Sec. 601.8  Settlements under existing contracts.

    Contracts for the purchase of helium or for the rent of Bureau-owned 
shipping containers which are in effect on the effective date of the 
amended regulations in this part shall remain in effect, subject to the 
terms and conditions of the amended regulations in this part, for a 
period of not more than 90 days after the effective date of these 
amended regulations or until replaced by new contract or contracts as 
described in these amended regulations, should such replacement occur 
prior to expiration of the 90 days. In the event that purchaser does not 
enter into replacement contract or contracts within 90 days after 
effective date of these regulations, the existing contract(s) shall 
terminate and purchaser shall pay any sums due Bureau under terms of the 
contracts and shall return any Bureau-owned shipping containers 
outstanding under any container rent contract so terminated.



Sec. 601.9  Shipping containers.

    (a) Containers may be provided by the purchaser or the Bureau. The 
purchaser may provide containers or may request the Bureau to provide 
them under contract. Containers provided by the purchaser must be 
satisfactory to the Bureau in all respects, must be free internally from 
oil or water, and shall comply with the requirements for shipment in 
interstate commerce. The Bureau will not use or fill any container which 
in its opinion is unsafe or unsuitable.
    (b) Provisions applicable to all types of containers supplied by the 
Bureau.Specific provisions for all types of containers, such as, 
cylinders, tank

[[Page 572]]

cars, tube trailers, tube modules, liquid helium trailers, and liquid 
helium dewars, are detailed in the container rental contract and the 
Schedule.



Sec. 601.10  [Reserved]



Sec. 601.11  Applicability to Federal Agencies.

    The regulations in this part are applicable to Federal agencies 
procuring helium or services from Bureau or using containers furnished 
by Bureau; except that Federal agencies shall not be required to: (a) 
enter into contracts for the purchase of helium or lease of containers, 
(b) furnish advance payments, or (c) provide surety for the return of 
containers or payment of bills.

[[Page 573]]





                       SUBCHAPTERS B--L [RESERVED]





  SUBCHAPTER M--RULES AND REGULATIONS FOR THE ADMINISTRATION OF GRANTS





PART 652--MINING AND MINERAL RESOURCES RESEARCH INSTITUTE PROGRAM--Table of Contents




Sec.
652.1  Scope.
652.2  Objectives.
652.3  Authority.
652.4  Administration.
652.5  Definitions.
652.6  Eligibility.
652.7  Responsibilities of institutions designated as mineral 
          institutes.
652.8  Applications for allotment grants.
652.9  Generic mineral technology centers.
652.10  Application for research grants.
652.11  Transfers of research and allotment grant funds.
652.12  Governing provisions for grants.
652.13  Reports.
652.14  Information collection.
652.15  Advisory committee.
652.16  Site visits.
652.17  Grant modifications.
652.18  Grant reduction and termination.

    Authority: 30 U.S.C. 1221-1230; Pub. L. 98-409; Pub. L. 100-483.

    Source: 54 FR 38378, Sept. 18, 1989, unless otherwise noted.



Sec. 652.1  Scope.

    This part sets forth policies and procedures for the assistance of 
institutions of higher learning that have been designated as State 
Mining and Mineral Resources Research Institutes and for the support of 
mining and mineral resources research at these institutions through 
specialized generic mineral technology research centers.



Sec. 652.2  Objectives.

    The objectives of the assistance provided by the Mining and Mineral 
Resources Research Institute program are:
    (a) To support research and training in mining and mineral resources 
problems related to the mission of the Department of the Interior;
    (b) To improve the advanced training of mineral scientists and 
engineers through grants which encourage State and industry support of 
mineral education;
    (c) To support, and encourage support of, research centers of 
generic expertise in mineral technology;
    (d) To assist the States in carrying on the work of competent and 
qualified mining and mineral resources research institutes; and
    (e) To provide support for graduate and postdoctoral students in 
mining and mineral resources disciplines including mining engineering, 
extractive metallurgy, geology, reclamation, engineering, economics, 
chemistry, physics, biology, ecology, and others.



Sec. 652.3  Authority.

    The authority for this program is the Mining and Mineral Resources 
Research Program Act of 1984 and the Mining and Mineral Resources 
Research Institute Amendments of 1988.
    (a) 30 U.S.C. 1221 authorizes the Secretary to make grants to assist 
States on a matching basis in carrying on the work of competent and 
qualified mining and mineral resources research institutes.
    (b) 30 U.S.C. 1222 authorizes the Secretary to make grants to the 
institutes for specific research and demonstration projects, and for 
research into any aspects of mining and mineral resources problems 
related to the mission of the Department of the Interior deemed 
desirable and not otherwise under study.
    (c) 30 U.S.C. 1229 authorizes the Secretary to appoint an Advisory 
Committee on Mining and Mineral Resources Research jointly chaired by 
the Assistant Secretary of the Interior responsible for minerals and 
mining and a committee member elected by the Committee from among those 
members who are not Federal employees.



Sec. 652.4  Administration.

    Responsibility for administration of the Mining and Mineral 
Resources Research Institute Program is assigned to the Director of the 
Bureau of Mines

[[Page 574]]

and subject to the supervisory authority of the Assistant Secretary to 
whom he/she reports.



Sec. 652.5  Definitions.

    As used in this part, the term--
    Act means the State Mining and Mineral Resources Research Program 
Act of 1984 and subsequent amendments.
    Advisory Committee means the Advisory Committee on Mining and 
Mineral Resources Research appointed by the Secretary pursuant to 30 
U.S.C. 1229.
    Allotment grant means funds made available to a mineral institute 
for the support of mineral-related research and education on a matching 
(formula) basis in a particular fiscal year pursuant to 30 U.S.C. 1221 
and under the regulations contained herein.
    Bureau means the Bureau of Mines.
    Call for proposals means a letter from the Director to eligible 
mineral institutes and generic mineral technology centers requesting 
proposals for allotment or research grants, and specifying the format 
and date for receipt at the Office and other conditions. Separate Calls 
for proposals are issued annually for allotment and research grants. 
Applications for funds may be submitted only in response to a Call for 
Proposals.
    Director means Director of the Bureau of Mines.
    Generic mineral technology center means a cooperative mineral 
resources research effort in a specific area of broad applicability 
across the minerals industry headquartered in one institute with 
participation by one or more affiliate mineral institutes as authorized 
under 30 U.S.C. 1222.
    Grant agreement means the legal document that sets forth the rules 
for the administration of the grant, including the responsibilities and 
privileges of the recipient, the amount of the award, reports required, 
and applicable rules and regulations.
    Mineral institute means a competent and qualified mining and mineral 
resources research institute, department, or component of a college or 
university that conducts mineral resources research, which is determined 
to be eligible in accordance with the provisions of the Act, and which 
is designated by the Secretary as a State Mining and Mineral Resources 
Institute.
    Mineral resources research means research, investigations, 
demonstrations, and experiments of a basic or practical nature relating 
to mineral exploration, extraction, processing, development, production, 
mining and technology, supply and demand, conservation and best use of 
available supplies, and the mineral-related aspects of other 
disciplines; and the training of mineral engineers and scientists 
through such activity; and the planning and coordination of such 
cooperative activity with other mineral institutes and those other 
agencies and individuals as may contribute to the solution of mining and 
mineral resources problems.
    Office means Office of Mineral Institutes.
    Secretary means the Secretary of the Interior or his authorized 
representative.



Sec. 652.6  Eligibility.

    Only institutions of higher learning (post-secondary institutions 
having graduate research programs) designated by the Secretary, after 
consultation with, and upon the advice of the Advisory Committee, as a 
State Mining and Mineral Resources Research Institute are eligible to 
receive funds under this program. Only one institution may be designated 
per State. To qualify as a mineral institute, institutions must meet all 
the following criteria as determined by the Advisory Committee:
    (a) Be either a public college or university or, in a State not 
having an eligible public college or university, a private college or 
university in that State.
    (b) Be recommended by the Governor of the State, as eligible, in the 
absence of contrary act by the legislature of the State.
    (c) Have in existence a substantial program of graduate instruction 
and research in mining or mineral extraction or closely related fields 
which has a demonstrated history of achievement.
    (d) Evidence institutional commitment to the purposes of the Act.

[[Page 575]]

    (e) Exhibit significant industrial cooperation in activities within 
the scope of the Act.
    (f) Have in existence an engineering program in mining or minerals 
extraction that is accredited by the Accreditation Board for Engineering 
and Technology, or show evidence of equivalent institutional capability.
    (g) Employ at least six full-time permanent faculty members in the 
department or component of the institution conducting instruction and 
research in mining and mineral extraction.
    (h) Meet such other criteria as the Advisory Committee shall deem 
necessary or desirable.



Sec. 652.7  Responsibilities of institutions designated as mineral institutes.

    (a) Each institution designated as mineral institute has the duty of 
planning and conducting mineral resources research. To carry out its 
responsibility, it shall appoint a mineral institute director from its 
faculty or staff, who is professionally qualified in minerals research 
and education.
    (b) Mineral institute directors shall be responsible for preparation 
of allotment grant proposals; for the technical administration of 
allotment grant agreements; for periodic reporting to the Bureau of 
Mines; for the preparation and transmission to the Bureau of Mines of an 
annual institute status report; for providing such coordination as may 
be necessary between various departments, units, and individuals at that 
institution to achieve a focused minerals program of value to the 
mineral institute's State and region; for the coordination between and 
among the minerals programs of the several mineral institutes; for 
responding to requests for information regarding the minerals program at 
that institution from the Bureau of Mines, the Advisory Committee, and 
the public; and for the selection and transmission of the best research 
proposals from that institution for inclusion in the generic mineral 
technology center program.



Sec. 652.8  Applications for allotment grants.

    Applications for annual allotment grants shall be submitted in 
response to an annual call for proposals issued by the Bureau of Mines 
to mineral institutes. To receive a new allotment grant, a mineral 
institute must have submitted all reports due and shall not have been 
found by the Secretary to have improperly diminished, lost, or 
misapplied funds previously received. Such funds shall be replaced by 
the State concerned and until so replaced no subsequent grant shall be 
allotted or paid to the institute of that State. Each allotment grant 
application shall be responsive to 30 U.S.C. 1221(b) and as a minimum 
shall consist of the following elements in duplicate:
    (a) A completed Standard Form 424.
    (b) A plan to provide for the training of individuals as mineral 
engineers and scientists under a curriculum appropriate to the field of 
mineral resources and mineral engineering and related fields.
    (c) A budget to support that plan.
    (d) Assurance that Federal funds will supplement and, to the extent 
practicable, increase the level of funds that would otherwise have been 
available for the purposes of the Act, and in no case supplant such 
funds.
    (e) Such other information as is requested in the Call for 
Proposals.

The Secretary shall deny or reduce funds to mineral institutes where 
proposals or portions thereof are not complementary to the mission of 
the Department or the goals of this program.



Sec. 652.9  Generic mineral technology centers.

    All research supported under this program, except for that funded 
through allotment grants, is funded through established generic mineral 
technology centers (generic centers). Each generic center provides a 
focus for mineral research in a specific area of broad applicability 
across the minerals industry. Each generic center has the following 
characteristics:
    (a) It is headquartered in one mineral institute with participation 
by one or more affiliate institutions.
    (b) A generic center director supervises the operation of the center 
including the coordination of related projects; makes arrangements for 
an annual seminar; provides for operation of a reference center; makes 
recommendations to the Bureau of Mines

[[Page 576]]

on budget revisions, equipment purchases, and other grant modifications; 
and provides technical leadership for the center.
    (c) A reference center serves as a centralized repository of 
literature concerning the generic research area and also is a repository 
of all periodic and final reports, dissertations, and contributions to 
the technical literature resulting from generic center research.
    (d) An annual seminar provides opportunity for students and 
principal investigators to exchange ideas and present their latest 
research in the generic area.
    (e) A Research Council, consisting of experts in the generic 
research area from industry, government and, where possible, academia, 
attends the annual seminars, receives periodic reports, evaluates 
research proposals, and provides recommendations to the Bureau of Mines 
on the program of the center.
    (f) New proposals for research, submitted through generic center and 
mineral institute directors, are evaluated on a competitive basis, in 
writing, and through Council discussion.



Sec. 652.10  Application for research grants.

    Proposals may be submitted to the Bureau of Mines in any of the 
generic mineral technology areas through mineral institute and generic 
mineral technology center directors in response to an annual call for 
proposals which describes the format of the proposals. Proposals shall 
address the requirements of 30 U.S.C. 1222 (b) through (d) as detailed 
in the call for proposals. No portion of any research grant shall be 
applied to the acquisition by purchase or lease of any land or interests 
therein or the rental, purchase, construction, preservation or repair of 
any building.



Sec. 652.11  Transfers of research and allotment grant funds.

    Under 30 U.S.C. 1223(b), mineral institutes are authorized to 
conduct cooperative programs with other mineral institutes and with such 
other agencies and individuals as may contribute to the solution of the 
mining and mineral resource problems involved. Mineral institutes may 
utilize their funds to pay for projects at other institutions under the 
following limitations:
    (a) The mineral institute director (for allotment grants) or the 
generic mineral technology center director (for research grants) for the 
institution awarded the funds by the Bureau, or the designated 
representative of the above, shall administer, conduct and supervise all 
funded programs.
    (b) All proposals to fund noninstitute activities shall be 
specifically set forth in the grant proposal applications required under 
Sec. 652.8 and Sec. 652.10 and must be explicitly approved by the Bureau 
of Mines.
    (c) All subgrants and subcontracts, service agreements, and 
interdivisional work authorizations shall be subject to the same terms 
and conditions as the grant.
    (d) Copies of all agreements for funding of programs conducted by 
noninstitute organizations, universities, or individuals shall be made 
available to the Bureau of Mines upon request.



Sec. 652.12  Governing provisions for grants.

    Performance under all grants shall be in accord with the terms and 
conditions set forth in OMB Circulars A-110 (General Administration), A-
21 (Cost Principles), A-88 (Indirect Cost Rates and Audit), and all 
other applicable laws and regulations. Copies of the OMB circulars are 
available from Publications Services, 725 17th Street NW., Room 2200, 
Washington, DC 20503. All uses, products, processes, patents, and other 
developments under this program, with such exceptions as the Secretary 
may make in the public interest, are to be made promptly available to 
the public. Patentable inventions shall be governed by the provisions of 
Pub. L. 96-517.

[54 FR 38378, Sept. 18, 1989, as amended at 55 FR 35300, Aug. 29, 1990]



Sec. 652.13  Reports.

    The following reports are required from program participants:
    (a) Annual Institute Status Report (30 U.S.C. 1223(a)(3)). On or 
before September 1 of each year, the mineral institute director for each 
institute shall submit to the Office a written report on work 
accomplished; the status of

[[Page 577]]

projects underway; a listing of scholarship and fellowship holders 
supported under this program, their departmental affiliation, 
citizenship, amount of award, and thesis title, if selected; and a 
statement of disbursements of funds received under this program. This 
report shall cover all activities under both the allotment grant and 
research grant program.
    (b) Periodic Technical Reports. Each mineral institute and generic 
center director shall make brief periodic written reports as specified 
in the grant document to the Office describing progress made on each 
active project. Generic center directors shall also send their periodic 
reports to members of the applicable Research Councils.
    (c) Periodic Financial Reports. Each mineral institute and generic 
center shall submit completed Standard Form-269 reports concurrent with 
the periodic technical progress reports.
    (d) Annual Property Report. Each mineral institute and generic 
center shall submit by November 15 a completed Bureau of Mines Form 6-
359 on nonexpendable property.
    (e) Final Reports. The annual institute status report will serve as 
the final report for allotment grants. A final report is required for 
each approved generic center research project. Principal investigators 
are encouraged to publish in the technical literature any information 
developed in the course of carrying out a research project. A published 
journal article may be substituted for a final report, provided the 
Grantee delivers five copies of the reprint to the Office. If the 
findings of a research project are not published, five copies of a final 
report shall be furnished. An unpublished final report should be 
prepared in accordance with ANSI 239.18-1974, ``American National 
Standard Guidelines for Format and Production of Scientific and 
Technical Reports.''
    (1) Credits. Every final research report or publication in the 
technical literature shall contain one of the following statements or 
the equivalent:

    This research has been supported by the Department of the Interior's 
Mineral Institute Program administered by the Bureau of Mines under 
allotment grant number ________.
    This research has been supported by the Department of the Interior's 
Mineral Institute Program administered by the Bureau of Mines through 
the Generic Mineral Technology Center for ________ under research grant 
number ________.



Sec. 652.14  Information collection.

    The information collection requirements contained in this section 
have been approved by the Office of Management and Budget under 44 
U.S.C. 3501 et seq. and assigned clearance number 1032-0116. The 
information is being collected to evaluate the effectiveness of the 
programs and responses are required to obtain a benefit in accordance 
with 30 U.S.C. 1221-1230. Public reporting burden for this information, 
including the time for reviewing instructions, searching existing data 
sources, gathering and maintaining the data needed, and completing and 
reviewing the collection of information is as follows:

Performance Report..............................................16 hours
Report of Funded Scholarship and Fellowships.....................2 hours
Summary Report of Inventions and Subgrants........................1 hour
Grantee Inventory of Property Purchased from Grant Funds.........2 hours
Budget Information Report.......................................8 hours.

    Send comments regarding this burden estimate or any other aspect of 
this collection of information, including suggestions for reducing the 
burden, to Office of Statistical Standards, Bureau of Mines, Washington, 
DC 20241; and to the Office of Management and Budget, Paperwork 
Reduction Project (OMB No. 1032-0116), Washington, DC 20503.



Sec. 652.15  Advisory committee.

    An Advisory Committee on Mining and Mineral Resources Research, 
appointed by the Secretary under 30 U.S.C. 1229, shall consult with and 
make recommendations to the Secretary on the operation of and the making 
of grants under this program and it shall determine the eligibility of a 
college or university to participate as a Mining and Mineral Resources 
Research Institute under the Act and make such recommendation to the 
Secretary.

[[Page 578]]



Sec. 652.16  Site visits.

    In relation to the substantive scientific and administrative 
operations of grantees, the Bureau of Mines or the Advisory Committee 
may perform inspections of activities authorized and financed pursuant 
to these regulations. Such inspections may cover acceptability of 
progress, consistency with approved plans, and institute eligibility.



Sec. 652.17  Grant modifications.

    (a) The mineral institute and generic center directors are 
responsible for promptly notifying the Office of events which may 
require modification of grant agreements, such as:
    (1) Rebudgetings,
    (2) No-cost time extensions, or
    (3) Changes in scope.
    (b) Permission of the Office is also required for the following 
actions under a grant:
    (1) Equipment purchase of $1000 or more,
    (2) Property transfer, or
    (3) Foreign travel.



Sec. 652.18  Grant reduction and termination.

    If a mineral institute or generic mineral technology center does not 
follow the provisions and terms of a grant or does not fully implement a 
grant program, the Director may reduce the size of or may suspend or 
terminate a grant.

[54 FR 38378, Sept. 18, 1989; 55 FR 35301, Aug. 29, 1990]



PARTS 653--699 [RESERVED]





[[Page 579]]



                              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
  Redesignation Table
  List of CFR Sections Affected

[[Page 581]]

            Material Approved for Incorporation by Reference

                      (Revised as of July 1, 2000)

  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 19150, Detroit, Michigan 48219
ACI Standard 318-95, Building Code Requirements       250.101; 250.198; 
  for Reinforced Concrete, plus Commentary on         250.908(b)(4)(i), 
  Building Code Requirements for Reinforced          (b)(6)(i), (b)(7), 
  Concrete (ACI 318R-95).                            (b)(8)(i), (b)(9), 
                                                       (b)(10), (c)(3), 
                                                     (d)(1)(v), (d)(5), 
                                                        (d)(6), (d)(7), 
                                                        (d)(8), (d)(9), 
                                                    (e)(1)(i), (e)(2)(i)
ACI Standard 357-R-84, Guide for the Design and       250.101; 250.198; 
  Construction of Fixed Offshore Concrete                   250.900(g); 
  Structures, 1984.                                250.908(c)(2), (c)(3)


American Institute of Steel Construction, Inc.

  P.O. Box 4588, Chicago, Illinois 60680.
AISC Standard Specification for Structural Steel      250.101; 250.198; 
  for Buildings, Allowable Stress Design and         250.907(b)(1)(ii), 
  Plastic Design, June 1, 1989, with Commentary.            (c)(4)(ii), 
                                                             (c)(4)(vii)


American National Standards Institute (ANSI)

  Attention Sales Department, 1430 Broadway, New 
  York, NY 10018


American Society of Mechanical Engineers (ASME)

  United Engineering Center, 345 East 47th Street, 
  New York, NY 10017
ANSI/ASME Boiler and Pressure Vessel Code, Section 250.101(e); 250.198; 
  I, Rules for Construction of Power Boilers,            250.803(b)(1), 
  including Appendices, 1998 Edition; July 1, 1999           (b)(1)(i); 
  Addenda, Rules for Construction of Power              250.1629(b)(1), 
  Boilers, by ASME Boiler and Pressure Vessel                  (b)(1)(i)
  Committee Subcommittee on Power Boilers; and all 
  Section I Interpretations, Volume 43.
ANSI/ASME Boiler and Pressure Vessel Code, Section 250.101(e); 250.198; 
  IV, Rules for Construction of Heating Boilers,         250.803(b)(1), 
  including Nonmandatory Appendices A, B, C, D, E,           (b)(1)(i); 
  F, H, I, K, and L, and the Guide to                   250.1629(b)(1), 
  Manufacturers Data Report Forms, 1998 Edition;               (b)(1)(i)
July 1, 1999 Addenda, Rules for Construction of 
[[Page 582]]lers, by ASME Boiler and Pressure 
  Vessel Committee Subcommittee on Heating 
ANSI/ASME Boiler and Pressure Vessel Code, Section    250.101; 250.198; 
  VIII, Pressure Vessels, Divisions 1 and 2,             250.803(b)(1), 
  including Nonmandatory Appendices, 1995 Edition.           (b)(1)(i); 
                                                        250.1629(b)(1), 
                                                               (b)(1)(i)
ANSI/ASME Boiler and Pressure Vessel Code, Section            250.101(e)
  VIII, Rules for Construction of Pressure 
  Vessels, Divisions 1 and 2, including 
  Nonmandatory Appendices, 1998 Edition; July 1, 
  1999 Addenda, Rules for Construction of Pressure 
  Vessels, by ASME Boiler and Pressure Vessel 
  Committee Subcommittee on Pressure Vessels; and 
  all Section VIII Interpretations, Divisions 1 
  and 2, Volumes 43 and 44.IV Interpretations 
ANSI/ASME B 16.5-1988 (including Errata) and B        250.101; 250.198; 
  16.5a-1992 Addenda, Pipe Flanges and Flanged            250.1002(b)(2)
  Fittings.
ANSI/ASME B 31.8-1995, Gas Transmission and           250.101; 250.198; 
  Distribution Piping Systems.                               250.1002(a)
ANSI/ASME SPPE-1-1994 and SPPE-1d-1996 Addenda,       250.101; 250.198; 
  Quality Assurance and Certification of Safety         250.806(a)(2)(i)
  and Pollution Prevention Equipment Used in 
  Offshore Oil and Gas Operations.
ANSI Z88.2-1992, American National Standard for       250.101; 250.198; 
  Respiratory Protection.                            250.417(g)(4)(iv), 
                                                             (j)(13)(ii)


The American Petroleum Institute

  1220 L Street, NW., Washington, DC 20005-4070; 
  Telephone: (202) 682-8000
API Spec Q1, Specification for Quality Programs                250.198; 
  for the Petroleum and Natural Gas Industry,          250.806(a)(2)(ii)
  Sixth Edition, March 1, 1999.
API RP 2A, Recommended Practice for Planning,      250.101; 250.900(g); 
  Designing, and Constructing Fixed Offshore                  250.912(a)
  Platforms--Working Stress Design, Nineteenth 
  Edition, August 1, 1991, API Stock No. 811-
  00200.
API RP 2A-WSD, Recommended Practice for Planning,  250.198; 250.900(g); 
  Designing, and Constructing Fixed Offshore                 250.912 (a)
  Platforms--Working Stress Design, Twentieth 
  Edition, July 1, 1993, Supplement I, December 
  1996, Effective Date: February 1, 1997, API 
  Stock No. G00205.
API RP 2D, Recommended Practice for Operation and        250.108(a)(1); 
  Maintenance of Offshore Cranes, Fourth Edition,  250.120(c); 250.198; 
  August 1999.                                               250.1605(g)
API Spec 6A, Specification for Wellhead and                    250.198; 
  Christmas Tree Equipment, Seventeenth Edition,         250.806(a)(3); 
  February 1, 1996 API Stock No. G06A17.                250.1002(b)(1), 
                                                                  (b)(2)
API Spec 6A V1, Specification for Verification                 250.198; 
  Test of Wellhead Surface Safety Valves and               250.806(a)(3)
  Underwater Safety Valves for Offshore Service, 
  First Edition, February 1, 1996, API Stock No. 
  G06AV1.
API Spec 6D, Specification for Pipeline Valves                 250.198; 
  (Gate, Plug, Ball, and Check Valves), Twenty-           250.1002(b)(1)
  first Edition, March 31, 1994, including 
  Supplement 2, December 1, 1997 API Stock No. 
  G03200.
API Spec 14A, Specification for Subsurface Safety              250.198; 
  Valve Equipment, Ninth Edition, July 1, 1994,            250.806(a)(3)
  API Stock No. G14A09.
API RP 14B Recommended Practice for Design,                    250.198; 
  Installation, Repair, and Operation of                 250.801(e)(4); 
  Subsurface Safety Valve Systems, Fourth Edition,      250.804(a)(1)(i)
July 1, 1994, with Errata dated June, 1996, API 
[[Page 583]]14B04.

API RP 14C for Analysis, Design, Installation, and    250.101; 250.198; 
  Testing of Basic Surface Safety Systems for       250.802(b), (e)(2); 
  Offshore Production Platforms, Sixth Edition,             250.803(a), 
  March 1998, API Stock No. G14C06.                  (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); 
  Volumes 43 and 44.                               250.1628(c), (d)(2); 
                                                        250.1629(b)(2), 
                                                             (b)(4)(v); 
                                                             250.1630(a)
API Spec 14D, Specification for Wellhead Surface               250.101; 
  Safety Valves and Underwater Safety Valves for           250.806(a)(3)
  Offshore Service, Ninth Edition, June 1, 1994, 
  with Errata dated August 1, 1994.
API RP 14E, Recommended Practice for Design and                250.198; 
  Installation of Offshore Production Platform           250.802(e)(3); 
  Piping Systems, Fifth Edition, October 1, 1991,       250.1628(b)(2), 
  API Stock No. G07185.                                           (d)(3)
API RP 14F, Recommended Practice for Design and    250.114(c); 250.198; 
  Installation of Electrical Systems for Offshore           250.403(c); 
  Production Platforms, Third Edition, September      250.803(b)(9)(v); 
  1, 1991, API Stock No. G07190.                       250.1629(b)(4)(v)
API RP 14G, Recommended Practice for Fire             250.101; 250.198; 
  Prevention and Control on Open Type Offshore           250.803(b)(8), 
  Production Platforms, Third Edition, December 1,           (b)(9)(v); 
  1993 API Stock No. G07194.                            250.1629(b)(3), 
                                                               (b)(4)(v)
API RP 14H, Recommended Practice for the              250.101; 250.198; 
  Installation, Maintenance and Repair of Surface           250.802(d); 
  Safety Valves and Underwater Safety Valves               250.804(a)(4)
  Offshore, Fourth Edition, July 1, 1994, API 
  Stock No. G14H04.
API RP 500, Recommended Practice for               250.114(a); 250.198; 
  Classification of Locations for Electrical                250.410(e); 
  Installations at Petroleum Facilities Classified    250.802(e)(4)(i); 
  as Class 1, Division 1 and Division 2, Second       250.803(b)(9)(i); 
  Edition, November 1997, API Stock No. C50002.         250.1628(b)(3); 
                                                     250.1628(d)(4)(i); 
                                                       250.1629(b)(4)(i)
API RP 505, Recommended Practice for                        250.114(a); 
  Classification of Locations for Electrical                250.410(e); 
  Installations at Petroleum Facilities Classified    250.802(e)(4)(i); 
  as Class 1, Zone 0, Zone 1, and Zone 2, First       250.803(b)(9)(i); 
  Edition, November 1997, API Stock No. C50501.         250.1628(b)(3); 
                                                     250.1628(d)(4)(i); 
                                                       250.1629(b)(4)(i)
API Standard 2545, Method of Gauging Petroleum and             250.101; 
  Petroleum Products, October 1965, reaffirmed            250.1202(l)(4)
  October 1992, API Stock No. 852-25450.
API Standard 2550, Method for Measurement and                    250.101
  Calibration of Upright Cylindrical Tanks, First 
  Edition, October 1965, API Stock No. 852-25500.
API Standard 2551, Standard Method for Measurement             250.198; 
  and Calibration of Horizontal Tanks, First              250.1202(l)(4)
Edition, 1965, reaffirmed January 1997; API 
[[Page 584]]25510.

API Standard 2552, Measurement and Calibration of              250.198; 
  Spheres and Spheroids, First Edition, 1966,             250.1202(l)(4)
  reaffirmed January 1997, API Stock No. H25520.
API Standard 2555, Method for Liquid Calibration               250.198; 
  of Tanks, First Edition, September 1966,                250.1202(l)(4)
  reaffirmed January 1997, API Stock No. H25550 
  (also available as ANSI/ASTM D 1406-65), 
  reapproved 1984.
API RP 2556, Recommended Practice for Correcting               250.198; 
  Gauge Tables for Incrustation, Second Edition,          250.1202(l)(4)
  August 1993, API Stock No. H25560.
API MPMS, Chapter 1, Vocabulary, Second Edition,       250.198; 250.1201
  July 1994, API Stock No., H01002.
API MPMS, Chapter 2, section 2A, Tank Calibration,             250.198; 
  Measurement and Calibration of Upright                  250.1202(1)(4)
  Cylindrical Tanks by the Manual Strapping 
  Method, First Edition, February 1995, API Stock 
  No. H022A1.
API MPMS, Chapter 2, section 2B, Calibration of                250.198; 
  Upright Cylindrical Tanks Using the Optical             250.1202(1)(4)
  Reference Line Method, First Edition, March 
  1989, reaffirmed May 1997, API Stock No. H30023.
API MPMS, Chapter 3, Tank Gauging, section 1A,                 250.198; 
  Standard Practice for the Manual Gauging of             250.1202(1)(4)
  Petroleum and Petroleum Products, First Edition, 
  December 1994, API Stock No. H031A1.
API MPMS, Chapter 3, section 1B, Standard Practice             250.198; 
  for Level Measurement of Liquid Hydrocarbons in         250.1202(1)(4)
  Stationary Tanks by Automatic Tank Gauging, 
  First Edition, April 1992, reaffirmed January 
  1997, API Stock No. H30060.
API MPMS, Chapter 4, Proving Systems, Section 1,        250.1202(a)(3); 
  Introduction, First Edition, May 1978,                          (f)(1)
  reaffirmed October 1993, API Stock No. H30081.
API MPMS, Chapter 4, Proving Systems, section 1,               250.198; 
  Introduction, First Edition, July 1988,               250.1202(a)(3), 
  reaffirmed October 1993, API Stock No. H30081.                  (f)(1)
API MPMS, Chapter 4, section 2, Conventional Pipe              250.198; 
  Provers, First Edition, October 1988, reaffirmed      250.1202(a)(3), 
  October 1993, API Stock No. H30082.                             (f)(1)
API MPMS, Chapter 4, section 3, Small Volume                   250.198; 
  Provers, First Edition, July 1988, reaffirmed         250.1202(a)(3), 
  October 1993, API Stock No. H30083.                             (f)(1)
API MPMS, Chapter 4, section 4, Tank Provers,                  250.198; 
  First Edition, October 1988, reaffirmed October       250.1202(a)(3), 
  1993, API Stock No. H30084.                                     (f)(1)
API MPMS, Chapter 4, section 5, Master-Meter                   250.198; 
  Provers, First Edition, October 1988, reaffirmed      250.1202(a)(3), 
  October 1993; API Stock No. H30085.                             (f)(1)
API MPMS, Chapter 4, Section 6, Pulse                          250.198; 
  Interpolation, Second Edition, May 1999, API       250.1202(a)(3) and 
  Stock No. H04062.                                               (f)(1)
API MPMS, Chapter 4, Section 7, Field Standard                 250.198; 
  Test Measures, Second Edition, December 1998,         250.1202(a)(3), 
  API Stock No. H04072.                                           (f)(1)
API MPMS, Chapter 5, Section 1, Metering, General              250.198; 
  Considerations for Measurement by Meters, Third         250.1202(a)(3)
Edition, September 1995, API Stock No. H05013.
[[Page 585]]

API MPMS, Chapter 5, section 2, Measurement of                 250.198; 
  Liquid Hydrocarbons by Displacement Meters,             250.1202(a)(3)
  Second Edition, November 1987, reaffirmed 
  January 1997, API Stock No. H30102.
API MPMS, Chapter 5, section 3, Measurement of        250.101; 250.198; 
  Liquid Hydrocarbons by Turbine Meters, Third            250.1202(a)(3)
  Edition, September 1995, API Stock No. H05033.
API MPMS, Chapter 5, section 4, Accessory                     250.1(d); 
  Equipment for Liquid Meters, Third Edition,        250.180(c)(6)(ii); 
  September 1995, API Stock No. H05043.                        250.198; 
                                                          250.1202(a)(3)
API MPMS, Chapter 5, section 5, Fidelity and                   250.198; 
  Security of Flow Measurement Pulsed-Data                250.1202(a)(3)
  Transmission Systems, First Edition, June 1982, 
  reaffirmed January 1997; API Stock No. H30105.
API MPMS, Chapter 5.1, Foreword, General                         250.1; 
  Considerations and Scope, First Edition,             250.180(c)(6)(ii)
  November 1976, API Stock No. 852-30101.
API MPMS, Chapter 5.2, Measurement of Liquid                     250.1; 
  Hydrocarbons by Displacement Meter Systems,          250.180(c)(6)(ii)
  First Edition, January 1977, API Stock No. 852-
  30102.
API MPMS, Chapter 5.3, Turbine Meters, First                     250.1; 
  Edition, July 1976, API Stock No. 852-30103.         250.180(c)(6)(ii)
API MPMS, Chapter 5.4, Instrumentation or                        250.1; 
  Accessory Equipment for Liquid Hydrocarbon           250.180(c)(6)(ii)
  Metering Systems, First Edition, July 1976, API 
  Stock No. 852-30104.
API MPMS, Chapter 5.5, Fidelity and Security of                  250.1; 
  Flow Measurement Pulsed Data Transmission            250.180(c)(6)(ii)
  Systems, First Edition, June 1982, API Stock No. 
  852-30105.
API MPMS, Chapter 6, Metering Assemblies, section             250.1(d); 
  1, Lease Automatic Custody Transfer (LACT)              250.180(c)(6) 
  Systems, Second Edition, May 1991, reaffirmed      (iii)(A); 250.198; 
  July 1996, API Stock No. H30121.                        250.1202(a)(3)
API MPMS, Chapter 6, section 6, Pipeline Metering             250.1(d); 
  Systems, Second Edition, May 1991, reaffirmed           250.180(c)(6) 
  July 1996, API Stock No. H30126.                   (iii)(B); 250.198; 
                                                          250.1202(a)(3)
API MPMS, Chapter 6, section 7, Metering Viscous               250.198; 
  Hydrocarbons, Second Edition, May 1991, API             250.1202(a)(3)
  Stock No. H30127, reaffirmed July 1996.
API MPMS, Chapter 6.1, LACT Systems, First         250.1; 250.180(c)(6) 
  Edition, February 1981, API Stock No. 852-30121.              (iii)(A)
API MPMS, Chapter 6.6, Pipeline Metering Systems,  250.1; 250.180(c)(6) 
  First Edition, August 1981, API Stock No. 852-                (iii)(B)
  30126.
API MPMS, Chapter 6.7, Metering Viscous            250.1; 250.180(c)(6) 
  Hydrocarbons, First Edition, January 1981, API                (iii)(C)
  Stock No. 852-30127.
API MPMS, Chapter 7, Temperature Determination,               250.1(d); 
  section 2, Dynamic Temperature Determination,    250.180(c)(6)(iv) (A) 
  Second Edition, March 1995, API Stock No.         and (f)(2)(iii)(A); 
  H07022.                                                      250.198; 
                                                        250.1202(a)(3), 
                                                                  (l)(4)
API MPMS, Chapter 7, section 3, Static Temperature             250.198; 
  Determination Using Portable Electronic               250.1202(a)(3), 
  Thermometers, First Edition, July 1985,                         (l)(4)
reaffirmed May 1996, API Stock No. H30143.
[[Page 586]]

API MPMS, Chapter 7.2, Dynamic Temperature         250.1; 250.180(c)(6) 
  Determination, First Edition, June 1985, API      (iv)(A), and (f)(2) 
  Stock No. 852-30142.                                          (iii)(A)
API MPMS, Chapter 7.3, Static Temperature          250.1; 250.180(c)(6) 
  Determination Using Portable Electronic                  (iv)(B), and 
  Thermometers, First Edition, July 1985, API             (f)(2)(iii)(B)
  Stock No. 852-30143.
API MPMS, Chapter 8, Sampling, Section 1, Standard             250.198; 
  Practice for Manual Sampling of Petroleum and      250.1202(b)(4)(i), 
  Petroleum Products, Third Edition, October 1995,                (l)(4)
  API Stock No. H30161.
API MPMS, Chapter 8, section 2, Standard Practice              250.198; 
  for Automatic Sampling of Liquid Petroleum and        250.1202(a)(3), 
  Petroleum Products, Second Edition, October                     (l)(4)
  1995; API Stock No. H30162.
API MPMS, Chapter 8.1, Manual Sampling of          250.1; 250.180(c)(6) 
  Petroleum and Petroleum Products, First Edition,   (v), and (f)(2)(iv)
  October 1981, API Stock No. 852-30161.
API MPMS, Chapter 8.2, Automatic Sampling of       250.1; 250.180(c)(6) 
  Petroleum and Petroleum Products, First Edition,   (v), and (f)(2)(iv)
  April 1983, API Stock No. 852-30162.
API MPMS, Chapter 9, Density Determination,                    250.198; 
  Section 1, Hydrometer Test Method for Density,        250.1202(a)(3), 
  Relative Density (Specific Gravity), or API                     (l)(4)
  Gravity of Crude Petroleum and Liquid Petroleum 
  Products, First Edition, June 1981, reaffirmed 
  December 1998, API Stock No. H30181; also 
  available as ANSI/ASTM D 1298.
API MPMS, Chapter 9, section 2, Pressure                       250.198; 
  Hydrometer Test Method for Density or Relative        250.1202(a)(3), 
  Density, First Edition, April 1982, reaffirmed                  (l)(4)
  December 1998, API Stock No. H30182.
API MPMS, Chapter 9.1, Hydrometer Test Method for                250.1; 
  Density, Relative Density (Specific Gravity), or   250.180(c)(6)(vi), 
  API Gravity of Crude Petroleum and Liquid                and (f)(2)(v)
  Petroleum Products, First Edition, June 1981, 
  API Stock No. 852-30181.
API MPMS, Chapter 9.2, Pressure Hydrometer Test                  250.1; 
  Method for Density or Relative Density, First      250.180(c)(6)(vi), 
  Edition, April 1982, API Stock No. 852-30182.            and (f)(2)(v)
API MPMS, Chapter 10, Sediment and Water, section              250.198; 
  1, Determination of Sediment in Crude Oils and        250.1202(a)(3), 
  Fuel Oils by the Extraction Method, First                       (l)(4)
  Edition, April 1981, reaffirmed December 1993; 
  API Stock No. H30201.
API MPMS, Chapter 10, section 2, Determination of              250.198; 
  Water in Crude Oil by Distillation Method, First      250.1202(a)(3), 
  Edition, April 1981, reaffirmed December 1993;                  (l)(4)
  ANSI/ASTM D 4006, API Stock No. H30202.
API MPMS, Chapter 10, section 3, Determination of              250.198; 
  Water and Sediment in Crude Oil by the                250.1202(a)(3), 
  Centrifuge Method (Laboratory Procedure), First                 (l)(4)
  Edition, April 1981, reaffirmed December 1993, 
  API Stock No. H30203.
API MPMS, Chapter 10, section 4, Determination of              250.198; 
  Sediment and Water in Crude Oil by the                250.1202(a)(3), 
  Centrifuge Method (Field Procedure), Second                     (l)(4)
  Edition, May 1988, reaffirmed May 1998; API 
  Stock No. H30204.
API MPMS, Chapter 10.1, Determination of Sediment  250.1; 250.180(c)(6) 
  in Crude Oils and Fuel Oils by the Extraction           (vii)(A), and 
  Method, First Edition, April 1981, API Stock No.         (f)(2)(vi)(A)
  852-30201.
API MPMS, Chapter 10.2, Determination of Water in  250.1; 250.180(c)(6) 
  Crude Oil by the Distillation Method, First             (vii)(B), and 
  Edition, April 1981, API Stock No. 852-30202.            (f)(2)(vi)(B)

[[Page 587]]

API MPMS, Chapter 10.3, Determination of Water and 250.1; 250.180(c)(6) 
  Sediment in Crude Oil by the Centrifuge Method          (vii)(C), and 
  (Laboratory Procedure), First Edition, April             (f)(2)(vi)(C)
  1981, API Stock No. 852-30203.
API MPMS, Chapter 10.4 (Pub. L. 2542), Standard    250.1; 250.180(c)(6) 
  Methods of Test for Water and Sediment in Crude         (vii)(D), and 
  Oils, October 1970, API Stock No. 825-25420.             (f)(2)(vi)(D)
API MPMS, Chapter 11, Physical Properties Data,                250.198; 
  Addendum to Section 2.2, Compressibility Factors        250.1202(a)(3)
  for Hydrocarbons, Correlation of Vapor Pressure 
  for Commercial Natural Gas Liquids, First 
  Edition, December 1994 reaffirmed March 1997; 
  API Stock No. H27308.
API MPMS, Chapter 11.1, Volume Correction Factors,             250.198; 
  Volume I, Table 5A--Generalized Crude Oils and        250.1202(a)(3), 
  JP-4 Correction of Observed API Gravity to API          (g)(3), (l)(4)
  Gravity at 60\1/2\ F, and Table 6A--Generalized 
  Crude Oils and JP-4 Correction of Observed API 
  Gravity to API Gravity at 60\1/2\ F, First 
  Edition, August 1980, reaffirmed March 1997; API 
  Stock No. H27000.
API MPMS, Chapter 11.2.1, Compressibility Factors              250.198; 
  for Hydrocarbons: 0-90\1/2\ API Gravity Range,        250.1202(a)(3), 
  First Edition, August 1984, reaffirmed May 1996,                (g)(4)
  API Stock No. H27300.
API MPMS, 11.2.2, Compressibility Factors for                  250.198; 
  Hydrocarbons: 0.350-0.637 Relative Density            250.1202(a)(3), 
  (60\1/2\ F/60\1/2\ F) and -50\1/2\ F to 140\1/2\                (g)(4)
  F Metering Temperature, Second Edition, October 
  1986, reaffirmed March 1997, API Stock No. 
  H27307; also available as Gas Processors 
  Association (GPA) 8286.
API MPMS, Chapter 11.2.3, Water Calibration of                 250.198; 
  Volumetric Provers, First Edition, August 1984,         250.1202(f)(1)
  reaffirmed May 1996, API Stock No. H27310.
API MPMS, Chapter 12, Calculation of Petroleum                 250.198; 
  Quantities, Section 2, Calculation of Petroleum       250.1202(a)(3), 
  Quantities Using Dynamic Measurement Methods and        (g)(1), (g)(2)
  Volumetric Correction Factors, including Parts 1 
  and 2, Second Edition, May 1995; API Stock No. 
  H30302.
API MPMS, Chapter 12.2, Calculation of Liquid                    250.1; 
  Petroleum Quantities Measured by Turbine or        250.180(c)(6)(ix), 
  Displacement Meters, First Edition, September       (d)(3)(v)(A), and 
  1981, API Stock No. 852-30302.                            (d)(3)(v)(C)
API MPMS, Chapter 14, Natural Gas Fluids                       250.198; 
  Measurement, Section 3, Concentric Square-Edged         250.1203(b)(2)
  Orifice Meters, Part 1, General Equations and 
  Uncertainty Guidelines, Third Edition, September 
  1990, reaffirmed August 1995; Part 1, 1991, API 
  Stock No. H30350.
API MPMS, Chapter 14, Section 3, Part 2,                       250.198; 
  Specification and Installation Requirements,            250.1203(b)(2)
  Third Edition, February 1991, reaffirmed May 
  1996; API Stock No. H30351.
API MPMS, Chapter 14, Section 3, Part 3, Natural      250.198; 250.1203 
  Gas Applications, Third Edition, August 1992,                   (b)(2)
  reaffirmed December 1998.
API MPMS, Chapter 14, Section 5, Calculation of                250.198; 
  Gross Heating Value, Relative Density, and              250.1203(b)(2)
  Compressibility Factor for Natural Gas Mixtures 
  From Compositional Analysis, Revised 1996.
API MPMS, Chapter 14, Section 6, Continuous                    250.198; 
  Density Measurement, Second Edition, April 1991,        250.1203(b)(2)
  reaffirmed May 1998, API Stock No. H30346.
API MPMS, Chapter 14, Section 8, Liquefied                     250.198; 
  Petroleum Gas Measurement, Second Edition, July         250.1203(b)(2)
1997; reaffirmed May 1996; API Stock No. H14082.
[[Page 588]]

API MPMS, Chapter 14.3, Orifice Metering of         250.1; 250.181(c)(1)
  Natural Gas and Other Related Hydrocarbon 
  Fluids, Second Edition, September 1985, API 
  Stock No. 852-30343.
API MPMS, Chapter 14.5, Calculation of Gross        250.1; 250.181(c)(1)
  Heating Value, Specific Gravity, and 
  Compressibility of Natural Gas Mixtures from 
  Compositional Analysis, First Edition, January 
  1981, API Stock No. 852-30345.
API MPMS, Chapter 14.6, Installing and Proving      250.1; 250.181(c)(1)
  Density Meters Used to Measure Hydrocarbon 
  Liquid with Densities Between 0.3 to 0.7 gm/cc 
  at 15.56\1/2\ C (60\1/2\ F) and Saturation Vapor 
  Pressure, First Edition, September 1979, API 
  Stock No. 852-30346.
API MPMS, Chapter 14.8, Liquefied Petroleum Gas     250.1; 250.181(c)(1)
  Measurement, First Edition, February 1983, API 
  Stock No. 852-30348.
API MPMS, Chapter 20, Section 1, Allocation                    250.198; 
  Measurement, First Edition, September 1993, API         250.1202(k)(1)
  Stock No. H30730.
API MPMS, Chapter 21, Flow Measurement Using                   250.198; 
  Electronic Metering Systems, Section 1 -                250.1203(b)(4)
  Electronic Gas Measurement, First Edition, 
  September 1993, API Stock No. H30730.


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 C33-86, Standard Specification for                 250.1; 
  Concrete Aggregates, including Nonmandatory           250.138(b)(4)(i)
  Appendix, 1986.
ASTM Standard C33-93, Standard Specification for      250.101; 250.198; 
  Concrete Aggregates including Nonmandatory            250.908(b)(4)(i)
  Appendix.
ASTM Standard C 33-99a, Standard Specification for      250.908(b)(4)(i)
  Concrete Aggregates.
ASTM Standard C94-86b, Standard Specification for                250.1; 
  Ready-mixed Concrete, 1986.                           250.138(e)(2)(i)
ASTM Standard C94/C94M-99, Standard Specification       250.908(e)(2)(i)
  for Ready-Mixed Concrete.
ASTM Standard C94-96, Standard Specification for               250.198; 
  Ready-Mixed Concrete.                                 250.908(e)(2)(i)
ASTM Standard C150-86, Standard Specification for                250.1; 
  Portland Cement.                                      250.138(b)(2)(i)
ASTM Standard C150-95a, Standard Specification for             250.198; 
  Portland Cement.                                      250.908(b)(2)(i)
ASTM Standard C 150-99, Standard Specification for      250.908(b)(2)(i)
  Portland Cement.
ASTM Standard C 330-87, Standard Specification for               250.1; 
  Light-weight Aggregates for Structural Concrete.      250.138(b)(4)(i)
ASTM Standard C330-89, Standard Specification for              250.198; 
  Lightweight Aggregates for Structural Concrete.       250.908(b)(4)(i)
ASTM Standard C 330-99, Standard Specification for      250.908(b)(4)(i)
  Light-weight Aggregates for Structural Concrete.
ASTM Standard C 595-86, Standard Specification for               250.1; 
  Blended Hydraulic Cements, 1986.                      250.138(b)(2)(i)
ASTM Standard C595-94, Standard Specification for              250.198; 
  Blended Hydraulic Cements.                            250.908(b)(2)(i)
ASTM Standard C 595-98, Standard Specification for      250.908(b)(2)(i)
  Blended Hydraulic Cements.


The American Welding Society

  550 NW LeJeune Road, P.O. Box 351040, Miami, 
  Florida 33135

[[Page 589]]

AWS D1.1-96, Structural Welding Code--Steel, 1996,             250.101; 
  including Commentary.                               250.137(b)(1)(i), 
                                                               250.198; 
                                                        250.907(b)(1)(i)
AWS D1.4-79, Structural Welding Code--Reinforcing              250.101; 
  Steel, 1979.                                       250.138(e)(3)(ii); 
                                                               250.198; 
                                                       250.198(e)(3)(ii)


The National Association of Corrosion Engineers

  P.O. Box 218340, Houston, Texas 77218
NACE Standard MR-01-75 (1984 Editorial Revision),              250.101; 
  Material Requirements, Sulfide Stress Cracking      250.67(g)(4)(iv), 
  Resistant Metallic Material for Oil Field        (j)(13)(ii), (l)(1), 
  Equipment, with Supplement 1 issued January       (l)(2), (l)(3), and 
  1985, Supplement 2 issued February 1985,                        (l)(6)
  Supplement 3 issued March 1985, Supplement 4 
  issued May 1985, Supplement 5 issued July 1985, 
  Supplement 6 issued August 1985, Supplement 7 
  issued February 1986, and Supplement 8 issued 
  September 1986.
NACE Standard MR.01-75-96, Sulfide Stress                      250.198; 
  CrackingResistant Metallic Materials for Oil             250.417(p)(2)
  Field Equipment,January 1996.
NACE Standard MR0175-99, Sulfide Stress Cracking           250.417(p)(2)
  Resistant Metallic Materials for Oil Field 
  Equipment, revised January 1999.
NACE Standard RP 01-76-94, Standard Recommended      250.198; 250.907(d)
  Practice, Corrosion Control of Steel Fixed 
  Offshore Platforms Associated with Petroleum 
  Production.
NACE Standard RP-01-76 (1983 Revision),              250.101; 250.137(d)
  Recommended Practice, Corrosion Control of 
  Steel, Fixed Offshore Platforms Associated with 
  Petroleum Production.
NACE Standard RP-01-76 (1994 Revision) Recommended   250.101; 250.137(d)
  Practice, Corrosion Control of Steel Fixed 
  Offshore Platforms Associated with Petroleum 
  Production.



[[Page 591]]



                    Table of CFR Titles and Chapters




                      (Revised as of June 23, 2000)

                      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--[Reserved]

                        Title 3--The President

         I  Executive Office of the President (Parts 100--199)

                           Title 4--Accounts

         I  General Accounting Office (Parts 1--99)
        II  Federal Claims Collection Standards (General 
                Accounting Office--Department of Justice) (Parts 
                100--299)

                   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)
       VII  Advisory Commission on Intergovernmental Relations 
                (Parts 1700--1799)
      VIII  Office of Special Counsel (Parts 1800--1899)
        IX  Appalachian Regional Commission (Parts 1900--1999)
        XI  Armed Forces Retirement Home (Part 2100)
       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 (Part 3201)

[[Page 592]]

     XXIII  Department of Energy (Part 3301)
      XXIV  Federal Energy Regulatory Commission (Part 3401)
       XXV  Department of the Interior (Part 3501)
      XXVI  Department of Defense (Part 3601)
    XXVIII  Department of Justice (Part 3801)
      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 (Part 4301)
      XXXV  Office of Personnel Management (Part 4501)
        XL  Interstate Commerce Commission (Part 5001)
       XLI  Commodity Futures Trading Commission (Part 5101)
      XLII  Department of Labor (Part 5201)
     XLIII  National Science Foundation (Part 5301)
       XLV  Department of Health and Human Services (Part 5501)
      XLVI  Postal Rate Commission (Part 5601)
     XLVII  Federal Trade Commission (Part 5701)
    XLVIII  Nuclear Regulatory Commission (Part 5801)
         L  Department of Transportation (Part 6001)
       LII  Export-Import Bank of the United States (Part 6201)
      LIII  Department of Education (Parts 6300--6399)
       LIV  Environmental Protection Agency (Part 6401)
      LVII  General Services Administration (Part 6701)
     LVIII  Board of Governors of the Federal Reserve System (Part 
                6801)
       LIX  National Aeronautics and Space Administration (Part 
                6901)
        LX  United States Postal Service (Part 7001)
       LXI  National Labor Relations Board (Part 7101)
      LXII  Equal Employment Opportunity Commission (Part 7201)
     LXIII  Inter-American Foundation (Part 7301)
       LXV  Department of Housing and Urban Development (Part 
                7501)
      LXVI  National Archives and Records Administration (Part 
                7601)
      LXIX  Tennessee Valley Authority (Part 7901)
      LXXI  Consumer Product Safety Commission (Part 8101)
    LXXIII  Department of Agriculture (Part 8301)
     LXXIV  Federal Mine Safety and Health Review Commission (Part 
                8401)
     LXXVI  Federal Retirement Thrift Investment Board (Part 8601)
    LXXVII  Office of Management and Budget (Part 8701)

                          Title 6--[Reserved]

                         Title 7--Agriculture

            Subtitle A--Office of the Secretary of Agriculture 
                (Parts 0--26)
            Subtitle B--Regulations of the Department of 
                Agriculture

[[Page 593]]

         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)
      XIII  Northeast Dairy Compact Commission (Parts 1300--1399)
       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)
      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, 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)

[[Page 594]]

    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  Immigration and Naturalization Service, Department of 
                Justice (Parts 1--599)

                 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)
      XVII  Defense Nuclear Facilities Safety Board (Parts 1700--
                1799)
     XVIII  Northeast Interstate Low-Level Radioactive Waste 
                Commission (Part 1800)

                      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)

[[Page 595]]

        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 (Parts 400--499)
         V  Emergency Oil and Gas Guaranteed Loan Board (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)

                 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)

[[Page 596]]

        IV  Foreign-Trade Zones Board, Department of Commerce 
                (Parts 400--499)
       VII  Bureau of Export Administration, 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  United States Customs Service, Department of the 
                Treasury (Parts 1--199)
        II  United States International Trade Commission (Parts 
                200--299)
       III  International Trade Administration, Department of 
                Commerce (Parts 300--399)

[[Page 597]]

                     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, 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 Regulations (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  Board for International Broadcasting (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)

[[Page 598]]

                          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 
                Housing Commissioner, 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--999)
         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)

[[Page 599]]

                           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 (Part 1001)
       VII  Office of the Special Trustee for American Indians, 
                Department of the Interior (Part 1200)

                      Title 26--Internal Revenue

         I  Internal Revenue Service, Department of the Treasury 
                (Parts 1--799)

           Title 27--Alcohol, Tobacco Products and Firearms

         I  Bureau of Alcohol, Tobacco and Firearms, Department of 
                the Treasury (Parts 1--299)

                   Title 28--Judicial Administration

         I  Department of Justice (Parts 0--199)
       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)

                            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)

[[Page 600]]

       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  Pension and Welfare Benefits 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)
        VI  Bureau of Mines, Department of the Interior (Parts 
                600--699)
       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)

                      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)

[[Page 601]]

       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)
     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 Transportation (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 Improvement, 
                Department of Education (Parts 700--799)
        XI  National Institute for Literacy (Parts 1100--1199)
            Subtitle C--Regulations Relating to Education
       XII  National Council on Disability (Parts 1200--1299)

                        Title 35--Panama Canal

         I  Panama Canal Regulations (Parts 1--299)

[[Page 602]]

             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)
       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)
       XIV  Assassination Records Review Board (Parts 1400--1499)
        XV  Oklahoma City National Memorial Trust (Part 1501)

             Title 37--Patents, Trademarks, and Copyrights

         I  Patent and Trademark Office, Department of Commerce 
                (Parts 1--199)
        II  Copyright Office, Library of Congress (Parts 200--299)
        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 Rate Commission (Parts 3000--3099)

                  Title 40--Protection of Environment

         I  Environmental Protection Agency (Parts 1--799)
         V  Council on Environmental Quality (Parts 1500--1599)
       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)

[[Page 603]]

        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, Department of Labor 
                (Parts 61-1--61-999)
            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)
       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)
            Subtitle D--Other Provisions Relating to Property 
                Management [Reserved]
            Subtitle E--Federal Information Resources Management 
                Regulations System
       201  Federal Information Resources Management Regulation 
                (Parts 201-1--201-99) [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 303-70)
       304  Payment from a Non-Federal Source for Travel Expenses 
                (Parts 304-1--304-99)

                        Title 42--Public Health

         I  Public Health Service, Department of Health and Human 
                Services (Parts 1--199)
        IV  Health Care Financing Administration, 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)

[[Page 604]]

       III  Utah Reclamation Mitigation and Conservation 
                Commission (Parts 10000--10005)

             Title 44--Emergency Management and Assistance

         I  Federal Emergency Management Agency (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)
         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)

[[Page 605]]

                          Title 46--Shipping

         I  Coast Guard, Department of Transportation (Parts 1--
                199)
        II  Maritime Administration, Department of Transportation 
                (Parts 200--399)
       III  Coast Guard (Great Lakes Pilotage), Department of 
                Transportation (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  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  United States 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)

[[Page 606]]

        34  Department of Education Acquisition Regulation (Parts 
                3400--3499)
        35  Panama Canal Commission (Parts 3500--3599)
        44  Federal Emergency Management Agency (Parts 4400--4499)
        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 (Parts 5300--5399)
        54  Defense Logistics Agency, Department of Defense (Part 
                5452)
        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  Research and Special Programs 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 Transportation (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  Bureau of Transportation Statistics, Department of 
                Transportation (Parts 1400--1499)

                   Title 50--Wildlife and Fisheries

         I  United States Fish and Wildlife Service, Department of 
                the Interior (Parts 1--199)

[[Page 607]]

        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



[[Page 609]]





           Alphabetical List of Agencies Appearing in the CFR




                      (Revised as of June 23, 2000)

                                                  CFR Title, Subtitle or 
                     Agency                               Chapter

Administrative Committee of the Federal Register  1, I
Advanced Research Projects Agency                 32, I
Advisory Commission on Intergovernmental          5, VII
     Relations
Advisory Council on Historic Preservation         36, VIII
African Development Foundation                    22, XV
  Federal Acquisition Regulation                  48, 57
Agency for International Development, United      22, II
     States
  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      7, XXXIV
       Extension Service
  Economic Research Service                       7, XXXVII
  Energy, Office of                               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        7, VIII; 9, II
       Administration
  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
Alcohol, Tobacco and Firearms, Bureau of          27, I
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         36, XI
   Compliance Board
[[Page 610]]

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
Assassination Records Review Board                36, XIV
Benefits Review Board                             20, VII
Bilingual Education and Minority Languages        34, V
     Affairs, Office of
Blind or Severely Disabled, Committee for         41, 51
     Purchase From People Who Are
Board for International Broadcasting              22, XIII
Broadcasting Board of Governors                   22, V
  Federal Acquisition Regulation                  48, 19
Census Bureau                                     15, I
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                       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
  Export Administration, Bureau of                15, VII
  Federal Acquisition Regulation                  48, 13
  Fishery Conservation and Management             50, VI
  Foreign-Trade Zones Board                       15, IV
  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                15, IX; 50, II, III, IV, 
       Administration                             VI
  National Telecommunications and Information     15, XXIII; 47, III
       Administration
  National Weather Service                        15, IX
  Patent and Trademark Office                     37, I
  Productivity, Technology and Innovation,        37, IV
       Assistant Secretary for
  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     24, V, VI
     Assistant Secretary for
Community Services, Office of                     45, X
Comptroller of the Currency                       12, I
Construction Industry Collective Bargaining       29, IX
     Commission
Consumer Product Safety Commission                5, LXXI; 16, II
Cooperative State Research, Education, and        7, XXXIV
     Extension Service
Copyright Office                                  37, II
Corporation for National and Community Service    45, XII, XXV
Cost Accounting Standards Board                   48, 99
Council on Environmental Quality                  40, V
Customs Service, United States                    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

[[Page 611]]

  Army Department                                 32, V; 33, II; 36, III, 
                                                  48, 51
  Defense Intelligence Agency                     32, I
  Defense Logistics Agency                        32, I, XII; 48, 54
  Engineers, Corps of                             33, II; 36, III
  Federal Acquisition Regulation                  48, 2
  National Imagery and Mapping Agency             32, I
  Navy Department                                 32, VI; 48, 52
  Secretary of Defense, Office of                 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
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      34, V
       Affairs, Office of
  Civil Rights, Office for                        34, I
  Educational Research and Improvement, Office    34, VII
       of
  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,  34, III
       Office of
  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
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                   5, LIV; 40, I, 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  24, I
     for
Executive Office of the President                 3, I
  Administration, Office of                       5, XV
  Environmental Quality, Council on               40, V
  Management and Budget, Office of                25, III, LXXVII; 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      15, XX
       States
Export Administration, Bureau of                  15, VII
Export-Import Bank of the United States           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

[[Page 612]]

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               4, II
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 Acquisition Regulation                  48, 44
Federal Employees Group Life Insurance Federal    48, 21
     Acquisition Regulation
Federal Employees Health Benefits Acquisition     48, 16
     Regulation
Federal Energy Regulatory Commission              5, XXIV; 18, I
Federal Financial Institutions Examination        12, XI
     Council
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    5, XIV; 22, XIV
     Counsel of the Federal Labor Relations 
     Authority
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       45, V
     United States
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 Accounting Office                         4, I, 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    41, 304
     Expenses
[[Page 613]]

  Payment of Expenses Connected With the Death    41, 303
       of Certain Employees
  Relocation Allowances                           41, 302
  Temporary Duty (TDY) Travel Allowances          41, 301
Geological Survey                                 30, IV
Government Ethics, Office of                      5, XVI
Government National Mortgage Association          24, III
Grain Inspection, Packers and Stockyards          7, VIII; 9, II
     Administration
Harry S. Truman Scholarship Foundation            45, XVIII
Health and Human Services, Department of          5, XLV; 45, Subtitle A
  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
  Health Care Financing Administration            42, IV
  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
Health Care Financing Administration              42, IV
Housing and Urban Development, Department of      5, LXV; 24, Subtitle B
  Community Planning and Development, Office of   24, V, VI
       Assistant Secretary for
  Equal Opportunity, Office of Assistant          24, I
       Secretary for
  Federal Acquisition Regulation                  48, 24
  Federal Housing Enterprise Oversight, Office    12, XVII
       of
  Government National Mortgage Association        24, III
  Housing--Federal Housing Commissioner, Office   24, II, VIII, X, XX
       of Assistant Secretary for
  Inspector General, Office of                    24, XII
  Multifamily Housing Assistance Restructuring,   24, IV
       Office of
  Public and Indian Housing, Office of Assistant  24, IX
       Secretary for
  Secretary, Office of                            24, Subtitle A, VII
Housing--Federal Housing Commissioner, Office of  24, II, VIII, X, XX
     Assistant Secretary for
Human Development Services, Office of             45, XIII
Immigration and Naturalization Service            8, I
Independent Counsel, Office of                    28, VII
Indian Affairs, Bureau of                         25, I, V
Indian Affairs, Office of the Assistant           25, VI
     Secretary
Indian Arts and Crafts Board                      25, II
Indian Health Service                             25, V
Information Resources Management, Office of       7, XXVII
Information Security Oversight Office, National   32, XX
     Archives and Records Administration
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
Intergovernmental Relations, Advisory Commission  5, VII
     on
Interior Department
  American Indians, Office of the Special         25, VII
       Trustee
  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         25, VI
       Secretary
  Indian Arts and Crafts Board                    25, II
  Land Management, Bureau of                      43, II
  Minerals Management Service                     30, II

[[Page 614]]

  Mines, Bureau of                                30, VI
  National Indian Gaming Commission               25, III
  National Park Service                           36, I
  Reclamation, Bureau of                          43, I
  Secretary of the Interior, Office of            43, Subtitle A
  Surface Mining and Reclamation Appeals, Board   30, III
       of
  Surface Mining Reclamation and Enforcement,     30, VII
       Office of
Internal Revenue Service                          26, I
International Boundary and Water Commission,      22, XI
     United States and Mexico, United States 
     Section
International Development, United States Agency   22, II
     for
  Federal Acquisition Regulation                  48, 7
International Development Cooperation Agency,     22, XII
     United States
International Fishing and Related Activities      50, III
International Investment, Office of               31, VIII
International Joint Commission, United States     22, IV
     and Canada
International Organizations Employees Loyalty     5, V
     Board
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                                5, XXVIII; 28, I
  Drug Enforcement Administration                 21, II
  Federal Acquisition Regulation                  48, 28
  Federal Claims Collection Standards             4, II
  Federal Prison Industries, Inc.                 28, III
  Foreign Claims Settlement Commission of the     45, V
       United States
  Immigration and Naturalization Service          8, I
  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
  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    41, 60
       of
  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
  Pension and Welfare Benefits Administration     29, XXV
  Public Contracts                                41, 50
  Secretary of Labor, Office of                   29, Subtitle A
  Veterans' Employment and Training, Office of    41, 61; 20, IX
       the Assistant Secretary for
  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
Management and Budget, Office of                  5, III, LXXVII; 48, 99
Marine Mammal Commission                          50, V
Maritime Administration                           46, II
Merit Systems Protection Board                    5, II
Micronesian Status Negotiations, Office for       32, XXVII
Mine Safety and Health Administration             30, I
Minerals Management Service                       30, II
Mines, Bureau of                                  30, VI
Minority Business Development Agency              15, XIV

[[Page 615]]

Miscellaneous Agencies                            1, IV
Monetary Offices                                  31, I
Multifamily Housing Assistance Restructuring,     24, IV
     Office of
National Aeronautics and Space Administration     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      5, LXVI; 36, XII
  Information Security Oversight Office           32, XX
National Bureau of Standards                      15, II
National Capital Planning Commission              1, IV
National Commission for Employment Policy         1, IV
National Commission on Libraries and Information  45, XVII
     Science
National Council on Disability                    34, XII
National Counterintelligence Center               32, XVIII
National Credit Union Administration              12, VII
National Drug Control Policy, Office of           21, III
National Foundation on the Arts and the           45, XI
     Humanities
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 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                       5, XLIII; 45, VI
  Federal Acquisition Regulation                  48, 25
National Security Council                         32, XXI
National Security Council and Office of Science   47, II
     and Technology Policy
National Telecommunications and Information       15, XXIII; 47, III
     Administration
National Transportation Safety Board              49, VIII
National Weather Service                          15, IX
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 Dairy Compact Commission                7, XIII
Northeast Interstate Low-Level Radioactive Waste  10, XVIII
     Commission
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
Panama Canal Commission                           48, 35
Panama Canal Regulations                          35, I
Patent and Trademark Office                       37, I
Payment From a Non-Federal Source for Travel      41, 304
     Expenses
Payment of Expenses Connected With the Death of   41, 303
     Certain Employees
Peace Corps                                       22, III
Pennsylvania Avenue Development Corporation       36, IX
Pension and Welfare Benefits Administration       29, XXV
Pension Benefit Guaranty Corporation              29, XL
Personnel Management, Office of                   5, I, XXXV; 45, VIII

[[Page 616]]

  Federal Acquisition Regulation                  48, 17
  Federal Employees Group Life Insurance Federal  48, 21
       Acquisition Regulation
  Federal Employees Health Benefits Acquisition   48, 16
       Regulation
Postal Rate 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             1, IV
     Fellowships
Presidential Documents                            3
Presidio Trust                                    36, X
Prisons, Bureau of                                28, V
Procurement and Property Management, Office of    7, XXXII
Productivity, Technology and Innovation,          37, IV
     Assistant Secretary
Public Contracts, Department of Labor             41, 50
Public and Indian Housing, Office of Assistant    24, IX
     Secretary for
Public Health Service                             42, I
Railroad Retirement Board                         20, II
Reclamation, Bureau of                            43, I
Refugee Resettlement, Office of                   45, IV
Regional Action Planning Commissions              13, V
Relocation Allowances                             41, 302
Research and Special Programs Administration      49, I
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     47, II
     National Security Council
Secret Service                                    31, IV
Securities and Exchange Commission                17, II
Selective Service System                          32, XVI
Small Business Administration                     13, I
Smithsonian Institution                           36, V
Social Security Administration                    20, III; 48, 23
Soldiers' and Airmen's Home, United States        5, XI
Special Counsel, Office of                        5, VIII
Special Education and Rehabilitative Services,    34, III
     Office of
State Department                                  22, I
  Federal Acquisition Regulation                  48, 6
Surface Mining and Reclamation Appeals, Board of  30, III
Surface Mining Reclamation and Enforcement,       30, VII
     Office of
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      12, V
     Treasury
Trade Representative, United States, Office of    15, XX
Transportation, Department of                     5, L
  Coast Guard                                     33, I; 46, I; 49, IV
  Coast Guard (Great Lakes Pilotage)              46, III
  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

[[Page 617]]

  Research and Special Programs 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 Statistics Brureau                 49, XI
Travel Allowances, Temporary Duty (TDY)           41, 301
Treasury Department                               5, XXI; 12, XV; 17, IV
  Alcohol, Tobacco and Firearms, Bureau of        27, I
  Community Development Financial Institutions    12, XVIII
       Fund
  Comptroller of the Currency                     12, I
  Customs Service, United States                  19, I
  Engraving and Printing, Bureau of               31, VI
  Federal Acquisition Regulation                  48, 10
  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     22, IV
     Commission
United States and Mexico, International Boundary  22, XI
     and Water Commission, United States Section
Utah Reclamation Mitigation and Conservation      43, III
     Commission
Veterans Affairs Department                       38, I
  Federal Acquisition Regulation                  48, 8
Veterans' Employment and Training, Office of the  41, 61; 20, IX
     Assistant Secretary for
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

[[Page 619]]

                                     

                                     



                           Redesignation Table




                            Derivation Table
------------------------------------------------------------------------
             New section                          Old section
------------------------------------------------------------------------
                           Subpart A--General
 
------------------------------------------------------------------------
250.0................................  250.0.
250.1................................  New Provision.
250.2................................  250.2.
250.3................................  New Provision.
250.4................................  250.10 \1\.
250.5................................  250.11 \1\.
250.6................................  250.13 \1\.
250.7................................  250.18 \1\.
250.8................................  250.31 \1\.
250.9................................  250.32 \1\.
250.10...............................  250.12 \1\.
  250.10(d)..........................  New Provision \2\.
250.11...............................  OCS Order No. 4.
250.12...............................  250.12 \1\.
250.13...............................  250.35.
  250.13(b)..........................  New Provision.
250.14...............................  250.53.
250.15...............................  250.37; OCS Order No. 1.
250.16...............................  250.58.
250.17...............................  250.90.
250.18...............................  250.3; OCS Order No. 12.
250.19...............................  250.45.
250.20...............................  250.46 \1\.
250.21...............................  250.19.
250.22...............................  OCS Order No. 5, paragraph 1.
250.23...............................  250.93.
250.24...............................   250.81.
 
------------------------------------------------------------------------
       Subpart B--Exploration and Development and Production Plans
 
------------------------------------------------------------------------
250.30...............................  250.34-1 and -2.
250.31...............................  250.34-1 and -2.
250.32...............................  250.17; OCS Order No. 11.
250.33...............................  250.34-1 and -3(a).
  250.33(d)..........................  New Provision.
250.34...............................  250.34-2 and -3(b).
  250.34(a)(2).......................  New Provision.
  250.34(a)(5).......................  New Provision.
 
------------------------------------------------------------------------
               Subpart C--Pollution Prevention and Control
 
------------------------------------------------------------------------
250.40...............................  250.43; OCS Order No. 7; OCS
                                        Order No. 1, paragraph 5.
250.40(b)(1).........................  New Provision.
  250.40(b)(5).......................  New Provision.
  250.40(c)(1).......................  New Provision.
  250.40(c)(2).......................  New Provision.
  250.40(c)(3).......................  New Provision.
  250.40(c)(4).......................  New Provision.
  250.40(d)..........................  New Provision.
  250.41.............................  OCS Order No. 7.
  250.42.............................  250.43; OCS Order No. 7.
  250.42(b)..........................  New Provision.
  250.42(c)..........................  New Provision.
  250.42(d)..........................  New Provision.
  250.42(i)..........................  New Provision.
  250.42(j)..........................  New Provision.
250.43...............................  OCS Order No. 7.
250.44...............................  250.2 \1\.
250.45...............................  250.57-1 \1\.
250.46...............................  250.57-2 \1\.
 
------------------------------------------------------------------------
                     Subpart D--Drilling Operations
 
------------------------------------------------------------------------
250.50...............................  250.30; 250.42; 250.46.
250.51...............................  .................................
  250.51(a)..........................  OCS Order No. 2, paragraph 2,
                                        Alaska OCS Order.
  250.51(b)..........................  New Provision.
  250.51(c)..........................  OCS Order No. 2, paragraph 2.4.
  250.51(d)..........................  OCS Order No. 2, paragraph 2.3.
  250.51(e)..........................  250.39; 250.40; OCS Order No. 2,
                                        paragraph 4.
  250.51(f)..........................  OCS Order No. 8.
  250.51(g)..........................  OCS Order No. 5, paragraph 7.
  250.51(h)..........................  OCS Order No. 5, paragraph 5.3.
  250.51(i)..........................  OCS Order No. 5, paragraph 5.3.
250.52...............................  OCS Order No. 2, Alaska OCS
                                        Region, paragraph 2.1.6, OCS
                                        Order No. 5, paragraph 5.4.
250.53...............................  OCS Order No. 2, Alaska OCS
                                        Region, paragraphs 12 (a), (b),
                                        (e), and (f); OCS Order No. 5,
                                        paragraph 5.1.10.
250.54...............................  250.41; OCS Order No. 2,
                                        paragraph 3.
250.55...............................  OCS Order No. 2, paragraph 3.6.
250.56...............................  250.41; OCS Order No. 2,
                                        paragraph 5.
250.57...............................  OCS Order No. 2, paragraph 5.7.
250.58...............................  OCS Order No. 2, paragraph 5.9.
250.59...............................  OCS Order No. 2, paragraphs 5.2,
                                        5.3, 5.4.1, and 5.5.
250.60...............................  250.41; OCS Order No. 2,
                                        paragraph 6.
250.61...............................  250.44.
250.62...............................  250.11; OCS Order No. 2,
                                        paragraph 10.
250.63...............................  250.41; OCS Order No. 2,
                                        paragraph 7.
250.64...............................  250.36; OCS Order No. 2,
                                        paragraphs 1.2 and 2.
250.65...............................  250.92.
250.66...............................  250.38; 250.92; 250.95.

[[Page 620]]

 
250.67...............................  OCS Order No. 2, paragraph 8; GSS-
                                        OCS-1.
 
------------------------------------------------------------------------
                  Subpart E--Well Completion Operations
 
------------------------------------------------------------------------
250.70...............................  New Provision.
250.71...............................  New Provision.
250.72...............................  New Provision.
250.73...............................  New Provision.
250.74...............................  New Provision.
250.75...............................  New Provision.
250.76...............................  New Provision.
250.77...............................  New Provision.
250.78...............................  New Provision.
250.79...............................  New Provision.
250.80...............................  New Provision.
250.81...............................  New Provision.
250.82...............................  New Provision.
250.83...............................  250.92.
250.84...............................  New Provision.
250.85...............................  New Provision.
250.86...............................  New Provision.
250.87...............................  OCS Order No. 6, paragraphs 1 and
                                        2.
 
------------------------------------------------------------------------
                   Subpart F--Well-Workover Operations
 
------------------------------------------------------------------------
250.90...............................  New Provision.
250.91...............................  New Provision.
250.92...............................  New Provision.
250.93...............................  New Provision.
250.94...............................  New Provision.
250.95...............................  New Provision.
250.96...............................  New Provision.
250.97...............................  New Provision.
250.98...............................  New Provision.
250.99...............................  New Provision.
250.100..............................  New Provision.
250.101..............................  New Provision.
250.102..............................  New Provision.
250.103..............................  250.92.
250.104..............................  New Provision.
250.105..............................  New Provision.
250.106..............................  New Provision.
250.107..............................  OCS Order No. 6, paragraphs 1 and
                                        2.
250.108..............................  New Provision.
 
------------------------------------------------------------------------
                     Subpart G--Abandonment of Wells
 
------------------------------------------------------------------------
250.110..............................  250.15; 250.44; OCS Order No. 3.
250.111..............................  250.44; 250.92; OCS Order No. 3.
250.112..............................  OCS Order No. 3.
250.113..............................  OCS Order No. 1, OCS Order No. 3.
250.114..............................  250.92; OCS Order No. 3.
 
------------------------------------------------------------------------
                  Subpart H--Production Safety Systems
 
------------------------------------------------------------------------
250.120..............................  OCS Order No. 5.
250.121..............................  250.41; OCS Order No. 5,
                                        paragraph 3.
250.122..............................  250.41(b); OCS Order No. 5,
                                        paragraph 4.
250.123..............................  OCS Order No. 5, paragraph 5.
250.124..............................  OCS Order No. 5, paragraphs 5.5
                                        and 5.6.
250.125..............................  OCS Order No. 5, paragraph 5.7
                                        \1\.
250.126..............................  OCS Order No. 5, paragraph 2.
250.127..............................  New Provision.
 
------------------------------------------------------------------------
                   Subpart I--Platforms and Structures
 
------------------------------------------------------------------------
250.130..............................  OCS Order No. 8, paragraph 1.
  250.130(g).........................  New Provision.
250.131..............................  OCS Order No. 8, paragraphs 2 and
                                        3.
250.132..............................  OCS Order No. 8, paragraphs
                                        1.4.1, 3.2.2, 3.3, and 3.4.
250.133..............................  OCS Order No. 8, paragraph 1.4.1.
250.134..............................  OCS Order No. 8, paragraph 1.4.2.
250.135..............................  OCS Order No. 8, paragraph 1.4.2.
250.136..............................  OCS Order No. 8, paragraph 1.4.2.
250.137..............................  OCS Order No. 8, paragraph 1.4.2.
250.138..............................  OCS Order No. 8, paragraph 1.4.2.
250.139..............................  OCS Order No. 8, paragraph 1.4.2.
250.140..............................  OCS Order No. 8, paragraph 1.4.2.
250.141..............................  OCS Order No. 8, paragraph 1.4.2.
250.142..............................  New Provision.
250.143..............................  OCS Order No. 3, paragraph 2.9.
250.144..............................  OCS Order No. 8, paragraph 4.
 
------------------------------------------------------------------------
             Subpart J--Pipelines and Pipeline Rights-of-Way
 
------------------------------------------------------------------------
250.150..............................  250.20; 256.8(a).
  250.150(a).........................  New Provision.
  250.150(c).........................  New Provision.
250.151..............................  New Provision.
250.152..............................  OCS Order No. 9.
  250.152(a).........................  New Provision.
  250.152(b).........................  New Provision.
  250.152(c).........................  New Provision.
  250.152(d).........................  New Provision.
  250.152(f).........................  New Provision.
250.153..............................  OCS Order No. 9, paragraph 1.C.
  250.153(a)(2)......................  New Provision.
  250.153(a)(3)......................  New Provision.
  250.153(a)(4)......................  New Provision.
  250.153(b).........................  New Provision.
  250.153(c).........................  New Provision.
250.154..............................  OCS Order No. 9, paragraphs
                                        1.A(2) (a) and (c).
  250.154(a).........................  New Provision.
  250.154(b)(6)......................  New Provision.
  250.154(b)(7)......................  New Provision.
  250.154(b)(8)......................  New Provision.
  250.154(b)(9)......................  New Provision.
  250.154(c).........................  New Provision.
250.155..............................  OCS Order No. 9, paragraph 1.E.
  250.155(b).........................  New Provision.
250.156..............................  New Provision.
250.157..............................  OCS Order No. 9, paragraph 2.
  250.157(a)(5)......................  New Provision.
  250.157(b).........................  New Provision.
250.158..............................  256.95; OCS Order No. 9,
                                        paragraph 1.E.
  250.158(a).........................  New Provision.
  250.158(c).........................  New Provision.
  250.158(d).........................  New Provision.
  250.150(f).........................  New Provision.
  250.158(g).........................  New Provision.
  250.158(h).........................  New Provision.
250.159..............................  256.83; 256.89 \1\; 256.101.
250.160..............................  256.92; 256.94; 256.100.
  250.160(d).........................  New Provision.
250.161..............................  256.85; 256.92; 256.94.
250.162..............................  256.95.
250.163..............................  256.97.
250.164..............................  256.98.
 
------------------------------------------------------------------------
                       Subpart K--Production Rates
 
------------------------------------------------------------------------
250.170..............................  OCS Order No. 11, paragraph 1.

[[Page 621]]

 
250.171..............................  OCS Order No. 11, paragraphs 2
                                        and 14.
  250.171(a).........................  New Provision.
  250.171(c).........................  New Provision.
250.172..............................  250.16; OCS Order No. 11,
                                        paragraphs 3 and 4.
  250.172(a)(1)......................  New Provision.
  250.172(a)(3)......................  New Provision.
  250.172(a)(5)......................  New Provision.
  250.172(a)(7)......................  New Provision.
  250.172(a)(8)......................  New Provision.
  250.172(b)(3)......................  New Provision.
  250.172(b)(4)......................  New Provision.
  250.172(b)(5)......................  New Provision.
  250.172(c).........................  New Provision.
250.173..............................  250.39; OCS Order No. 11,
                                        paragraphs 5, 6, 7, and 8.
250.174..............................  OCS Order No. 11, paragraph 9.
  250.174(a).........................  New Provision.
250.175..............................  250.55; OCS Order No. 11,
                                        paragraph 10; NTL 75-9 (5/13/
                                        75).
  250.175(a)(2)(i)...................  New Provision.
  250.175(a)(2)(ii)..................  New Provision.
  250.175(c).........................  New Provision.
250.176..............................  250.68; OCS Order No.11,
                                        paragraph 12.
250.177..............................  OCS Order No. 11, paragraph 15.
  250.177(b).........................  New Provision.
  250.177(c).........................  New Provision.
 
------------------------------------------------------------------------
      Subpart L--Production Measurement, Commingling, and Security
 
------------------------------------------------------------------------
250.180..............................  250.60; OCS Order No. 13,
                                        paragraphs 2, 3, and 4.
250.181..............................  250.61; OCS Order No. 13,
                                        paragraph 5.
250.182..............................  250.68; OCS Order No. 13,
                                        paragraph 6 \1\.
250.183..............................  New Provision.
 
------------------------------------------------------------------------
                         Subpart M--Unitization
 
------------------------------------------------------------------------
250.190..............................  250.50; 10 CFR 390.014(d).
250.191..............................  OCS Order No. 11, paragraph 16.
250.192..............................  250.51-1.
250.193..............................  250.51-2.
250.194..............................  Model Unit Agreement.
 
------------------------------------------------------------------------
                    Subpart N--Remedies and Penalties
 
------------------------------------------------------------------------
250.200..............................  250.80-1.
  250.200(a)(2)......................  New Provision.
250.201..............................  250.80-1.
250.202..............................  250.80-1.
250.203..............................  250.80-1.
250.204..............................  250.80-1.
250.205..............................  250.80-1.
250.206..............................  250.80-2.
 
------------------------------------------------------------------------
                           Subpart O--Training
 
------------------------------------------------------------------------
250.210..............................  250.42.
250.211..............................  250.42.
250.212..............................  250.42.
 
------------------------------------------------------------------------
                      Subpart P--Sulphur Operations
 
------------------------------------------------------------------------
250.250..............................  New Provision.
------------------------------------------------------------------------
\1\ No substantive change.
\2\ Codification of existing policy.
 
Note: The following old sections were deleted as unnecessary and
  redundant with no substantive change intended: 250.1, 250.4, 250.5,
  250.82, and 250.96.


[[Page 623]]



List of CFR Sections Affected



All changes in this volume of the Code of Federal Regulations which were 
made by documents published in the Federal Register since January 1, 
1986, 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, 1986, see the ``List of Sections 
Affected, 1949-1963, 1964-1972, 1973-1985'' published in seven separate 
volumes.

                                  1986

30 CFR
                                                                   51 FR
                                                                    Page
Chapter II
210  Authority citation revised.............................15766, 45882
210.10  Table amended..............................................15766
210.53  Redesignated as 210.54; new 210.53 added...................45882
210.54  Redesignated from 210.53...................................45882
210.200--210.203 (Subpart E)  Heading revised; sections added......15766
210.204  Added.....................................................45883
210  (Subpart F) Heading removed; new Subpart F redesignated from 
        210.300--210.301 (Subpart G)...............................15766
210.300--210.301  (Subpart G) Redesignated as Subpart F; new 
        Subpart G heading redesignated from Subpart H heading......15766
210  (Subpart H)  Heading redesignated as Subpart G heading........15766
212  Authority citation revised....................................15766
212.200 (Subpart E)  Heading revised...............................15767
212.200  (a) revised; (b)(1) amended...............................15767
212  (Subpart F) Heading removed; new Subpart F heading 
        redesignated from Subpart G heading........................15767
212  (Subpart G) Heading redesignated as Subpart F heading; new 
        Subpart G heading redesignated from Subpart H heading......15767
212  (Subpart H) Heading redesignated as Subpart G heading.........15767
216  Added..........................................................8175
    Authority citation revised.....................................45883
216.15  Added......................................................45883
218  Authority citation revised.............................15767, 19063
218.40  Redesignated from 218.56; (c) amended and (e) redesignated 
        as (d).....................................................15767
218.56  Redesignated as 218.40 and (c) amended and (e) 
        redesignated as (d); new 218.56 redesignated from 218.57 
                                                                   15767
218.57  Redesignated as 218.56.....................................15767
218.154  (a) and (b) revised.......................................19063
218.200  (Subpart E) Heading revised...............................15767
218  (Subpart F) Heading removed; new Subpart F redesignated from 
        218.300--218.301 (Subpart G)...............................15767
218.300--218.301  (Subpart G) Redesignated as Subpart F; new 
        Subpart G heading redesignated from Subpart H heading......15767
218  (Subpart H) Heading redesignated as Subpart G heading.........15767
251  Authority citation revised....................................17176
251.13  (b) revised................................................17176
252  Authority citation revised....................................17176

[[Page 624]]

252.2  (e) revised.................................................10382
252.3  (b)(1) and (e)(1) revised; (b)(2) and (e)(3) removed; 
        (b)(3) and (e)(4) redesignated as (b)(2) and (e)(3)........17176
256.22  Revised.....................................................6107
256.23--256.25 (Subpart D)  Heading revised; eff. 7-14-86..........21345
256.23  (b) revised; eff. 7-14-86..................................21345
256.26  (a) revised; eff. 7-14-86..................................21345
256.29  (c) amended................................................37178
Chapter IV
402  Added; eff. 10-1-86...........................................20963

                                  1987

30 CFR
                                                                   52 FR
                                                                    Page
Chapter II
206  Authority citation revised.....................................3798
206.100  Revised....................................................3798
208  Revised.......................................................41913
208.2  Corrected...................................................45528
209  Removed.......................................................41918
216  Authority citation revised....................................27546
216.40  (a) and (b) revised; (g) added.............................27546
218  Authority citation revised.....................................5458
    Authority citation revised; eff. 7-27-87.......................24451
    Authority citation revised..............................24451, 27546
218.40  (a) and (b) revised; (e) added.............................27546
    (e) correctly designated.......................................37452
218.51  Revised; eff. 7-27-87......................................23814
218.57  Added; eff. 7-31-87........................................24451
218.100  (a) revised; (c) added; eff. 7-27-87......................23815
218.150  (a) revised; eff. 7-27-87.................................23815
218.152  Revised....................................................5458
218.153  Removed....................................................5458
218.155  (a) revised; (d) removed; (e) and (f) redesignated as (d) 
        and (e); eff. 7-27-87......................................23815
218.156  Added; eff. 7-27-87.......................................23815
218.200  Redesignated as 218.202; new 218.200 added; eff. 7-27-87 
                                                                   23815
218.201  Added; eff. 7-27-87.......................................23815
218.202  Redesignated from 218.200; eff. 7-27-87...................23815
218.300  Revised; eff. 7-27-87.....................................23815
218.301  Redesignated as 218.302; new 218.301 added; eff. 7-27-87 
                                                                   23815
218.302  Redesignated from 218.301; eff. 7-27-87...................23815
250.3  (b) revised.................................................13237
250.45  (c) added; eff. 7-13-87....................................22307
250.93  Revised; eff. 7-27-87......................................23816
251.14-1  (e) added; eff. June 22, 1987 through 6-22-88............23441

                                  1988

30 CFR
                                                                   53 FR
                                                                    Page
Chapter II
202  Heading and authority citation revised.........................1217
    Authority citation revised......................................1270
    Seminars..................................................4011, 8181
202.51--202.53 (Subpart B)  Revised (202.52 and 202.53 
        redesignated from 202.152 and 202.151 and revised)..........1217
202.100--202.101 (Subpart C)  Revised...............................1217
202.100  Removed; new 202.100 redesignated from 202.150 and 
        revised.....................................................1217
202.101  Removed; new 202.101 added.................................1217
202.102  Removed....................................................1217
202.103  Removed....................................................1217
202.150  Redesignated as 202.100 and revised........................1217
202.151  Redesignated as 202.53 and revised.........................1217
202.152  Redesignated as 202.52 and revised.........................1217
202 (Subpart D)  Heading revised....................................1217
202.150--202.152 (Subpart D)  Sections added........................1271
202 (Subpart E)  Heading revised....................................1217
202 (Subpart F)  Heading revised....................................1217
202 (Subpart G)  Heading revised....................................1217
202 (Subpart H)  Heading revised....................................1217
202 (Subpart I)  Heading revised....................................1217
203  Authority citation revised.....................................1218
    Seminars..................................................4011, 8181
203.50 (Subpart B)  Heading revised.................................1218
203.50  Redesignated from 203.150...................................1218

[[Page 625]]

203 (Subpart C)  Heading revised....................................1218
203.100  Removed....................................................1218
203 (Subpart D)  Heading revised....................................1218
203.150  Redesignated as 203.50.....................................1218
203 (Subpart E)  Heading revised....................................1218
203.200  Redesignated as 203.250....................................1218
203.250 (Subpart F)  Heading revised................................1218
203.250  Redesignated from 203.200..................................1218
203 (Subpart G)  Heading revised....................................1218
203 (Subpart H)  Heading revised....................................1218
203 (Subpart I)  Heading revised....................................1218
206  Authority citation revised.............................45084, 45762
206  Seminars.................................................4011, 8181
206.10  Added.......................................................1272
206 (Subpart B)  Heading revised....................................1218
206.100--206.107 (Subpart C)  Heading revised.......................1218
206.100  Revised....................................................1218
206.101  Revised....................................................1218
    Amended........................................................45084
206.102  Revised....................................................1220
    (c)(1) amended.................................................45762
206.103  Removed....................................................1218
    Added...........................................................1221
206.104  Redesignated as 43 CFR Part 3162.7-4.......................1218
    Added...........................................................1222
    (b)(1) corrected...............................................24688
    (a)(2) amended.................................................45762
206.105  Revised....................................................1222
    Information collection requirements.............................4012
    (a)(1)(iii) amended; (c)(2)(viii) and (e)(1) revised...........45762
206.106--206.107  Removed...........................................1272
206.150--206.152 (Subpart D)  Heading revised.......................1218
206.150--206.159 (Subpart D)  Revised...............................1272
206.150  (e) (1) and (2) revised...................................45084
206.151  Amended...................................................45084
206.157  Information collection requirements........................4012
    (b)(5), (c)(2)(viii) and (e)(1) revised........................45762
206.159  Information collection requirements........................4012
    (a)(1)(iii), (c)(1)(iii) and (e)(1) revised....................45762
206 (Subpart E)  Heading revised....................................1218
206 (Subpart F)  Heading revised....................................1218
206 (Subpart G)  Heading revised....................................1218
206.300  Redesignated as 206.350....................................1218
206.301  Redesignated as 206.351....................................1218
    Redesignated from 43 CFR 3597.2................................39461
206.350--206.351 (Subpart H)  Heading revised.......................1218
206.350  Redesignated from 206.300..................................1218
206.351  Redesignated from 206.301..................................1218
206 (Subpart I)  Heading added......................................1218
207  Revised........................................................1225
    Seminars..................................................4011, 8181
208.3  Table revised...............................................34739
208.13  (a) revised................................................34739
210  Seminars.................................................4011, 8181
210.50--210.55 (Subpart B)  Heading revised.........................1226
210.53  (a) revised................................................16412
210.55  Added.......................................................1226
210 (Subpart C)  Heading revised....................................1226
210.100--210.105  Removed...........................................1226
210 (Subpart D)  Heading revised....................................1226
210.150--210.151  Removed...........................................1226
210 (Subpart F)  Heading revised....................................1226
210.300  Redesignated as 210.350....................................1226
210.301  Redesignated as 210.351....................................1226
210 (Subpart G)  Heading revised....................................1226
210.350--210.351 (Subpart H)  Added (210.350 and 210.351 
        redesignated from 210.300 and 210.301)......................1226
210 (Subpart I)  Heading revised....................................1226
216.10  Revised....................................................16412
216.15  Revised....................................................16412
216.40  (c) revised................................................16412
216.50  Added......................................................16412
218  Authority citation revised....................................43201
218.51  (a)(1) amended.............................................43201
218.155  (c) amended...............................................43201
241  Authority citation revised.....................................1218

[[Page 626]]

    Seminars..................................................4011, 8181
241.10  Removed.....................................................1226
241.50--241.53 (Subpart B)  Heading revised.........................1226
241.50  Amended.....................................................1226
241.53  Redesignated from 241.100 and heading revised; (c) removed
                                                                    1226
241 (Subpart C)  Heading revised....................................1226
241.100  Redesignated as 241.53 and heading revised; (c) removed 
                                                                    1226
241 (Subpart D)  Heading revised....................................1226
241 (Subpart E)  Heading redesignated as Subpart F heading; new 
        (Subpart E) heading added...................................1226
241 (Subpart F)  Heading redesignated as Subpart G heading; new 
        (Subpart F) heading redesignated from Subpart E heading.....1226
241 (Subpart G)  Heading redesignated as Subpart H heading; new 
        (Subpart G) heading redesignated from Subpart F heading.....1226
241 (Subpart H)  Heading removed; new (Subpart H) heading 
        redesignated from Subpart G heading.........................1226
241 (Subpart I)  Heading added......................................1226
250  Revised.......................................................10690
    Meetings.......................................................23758
250.1  Introductory text corrected.................................12227
250.30  Corrected..................................................26067
250.33  (b)(19)(i)(A)(5) corrected.................................26067
250.34  (b)(12)(i)(A)(5) corrected.................................26067
250.45  (e) table corrected........................................19856
    (b)(2) corrected...............................................26067
    (d) corrected..................................................26067
250.46  (a)(6) and (b) corrected...................................26067
250.51  (b) (1) and (2) corrected..................................12227
250.123  (b)(1) introductory text corrected........................12227
250.126  (b)(1) corrected..........................................12227
    Waiver.........................................................34493
250.134  (d)(4)(ii) corrected......................................26067
250.135  (d)(2)(iv) correctly revised; (d) (3) and (4) correctly 
        redesignated as (d) (4) and (5); new (d)(3) correctly 
        added......................................................26067
250.136  (b)(3)(i) corrected.......................................26067
250.137  (c)(3)(iv) corrected......................................26067
250.141  (b)(7)(iii)(D) corrected..................................26067
250.153  (a)(4) corrected..........................................12227
250.212  (a) revised...............................................27853
251  Authority citation revised.....................................4391
251.0  (e) amended and (f) added...................................24688
251.1  Revised.....................................................25256
251.5-1  (b) removed...............................................24688
251.5-3  Revised....................................................4392
251.14-1  (d) (1) and (2) and (e) revised; (c)(3) and (d)(3) 
        removed.....................................................4392
256.12  Added......................................................29886
256.26  (a) amended................................................29886
256.83--256.101 (Subpart N)  Removed...............................10777
280  Added.........................................................25256

                                  1989

30 CFR
                                                                   54 FR
                                                                    Page
Chapter II
202  Authority citation revised.....................................1522
    Training seminars..............................................12611
202.250  Redesignated from 203.250 (b) and revised..................1522
203  Authority citation revised.....................................1522
    Training seminars..............................................12611
203.250  (b) redesignated as 202.250 and revised; (c) through (k) 
        removed; section revised....................................1522
203.251  Added......................................................1522
206  Authority citation revised.....................................1522
    Training seminars..............................................12611
    Coal product valuation meeting.................................16105
206.10  Revised.....................................................1522
206.250--206.265 (Subpart F)  Revised...............................1523
210  Authority citation revised.....................................1531
    Training seminars..............................................12611
210.10  Revised.....................................................1531
212  Authority citation revised.....................................1532
    Subparts C, D, F and G headings revised.........................1532
    Subparts H and I headings added.................................1532
    Training seminars..............................................12611
212.200  (b) introductory text revised..............................1532
218.154  (a), (b) introductory text, (1), and (2) amended..........50616
250.3  (b) amended.................................................50616
250.12  (e)(5) amended.............................................50616
250.33  (b)(19) amended............................................50616

[[Page 627]]

250.34  (b)(12) introductory text and (q)(2) amended...............50616
250.51  (g) amended................................................50616
250.53  (c) amended................................................50616
250.79  Amended....................................................50616
250.85  (c)(1) amended.............................................50616
250.86  (a) amended................................................50616
250.100  Amended...................................................50616
250.105  (c)(1) amended............................................50616
250.106  (a) and (b)(2) amended....................................50617
250.107  (d) amended...............................................50617
250.121  (d) introductory text and (2) amended.....................50617
250.126  (a) amended...............................................50617
250.154  (b) (2) and (3) amended...................................50617
250.159  (a)(1) amended............................................50617
250.161  (c)(2) amended............................................50617
250.180  (f)(1) amended............................................50617
250.204  (e) amended...............................................50617
250.206  (a)(4) amended............................................50617
250.210  Introductory text and (b) amended.........................50617
251.5-3  (a) amended...............................................50617
251.6-3  (a) amended...............................................50617
252.5  (a) amended.................................................50617
256.0  Amended.....................................................50617
256.4  Amended......................................................2049
256.5  (d) and (k) revised..........................................2049
256.7  (a) amended.................................................50617
256.37  (d) removed.................................................2049
256.58  (d) removed; (e) through (g) redesignated as (d) through 
        (f).........................................................2049
256.72  Amended....................................................50617
256.73  (a) and (b) amended........................................50617
281  Added..........................................................2049
282  Added..........................................................2067
290  Authority citation revised....................................52797
290.3  (a) redesignated as (a)(1); (a)(2) added....................52797
290.5  Existing text designated as (a); (b) added..................52797
Chapter VI
652  Redesignated from Part 890 (Subchapter S) and revised.........38378

                                  1990

30 CFR
                                                                   55 FR
                                                                    Page
Chapter II
202  Training seminars.......................................7317, 51413
203  Training seminars........................................7317,51413
206  Training seminars........................................7317,51413
    Authority citation revised.....................................35433
206.251  Amended...................................................35433
206.257  (b)(5) removed; (b)(6) redesignated as (b)(5); (b)(1), 
        (5), (c)(3) and (g) revised................................35433
218  Authority citation revised....................................37230
218.50--218.57 (Subpart B)  Authority citation removed.............37230
218.54  Heading and (b) revised....................................37230
218.55  (c) revised................................................37230
218.103  (b) revised...............................................37230
220.21  (a)(2) revised..............................................1210
250.0  (a) amended.................................................47752
250.1  Introductory text, (c)(5) and (d) introductory text 
        revised; (d)(6) and (11) removed; (d)(1) through (5), (7), 
        (8) through (10), and (12) through (46) redesignated as 
        (d)(2) through (6), (9), (11) through (13), and (15) 
        through (49); new (d)(1), (7), (8), (10), and (14) added 
                                                                   10617
    (c)(5) and (d)(1) revised......................................37710
    (d)(3) amended.................................................47752
    (d)(2) and (15) revised........................................51415
250.19  (a) amended................................................47752
250.20  (c) added..................................................47752
250.32  (c) added..................................................47752
250.34  (t) amended................................................47752
250.51  (g) removed; (h) and (i) redesignated as (g) and (h).......47752
250.60  (e) amended................................................47752
250.72  Amended....................................................47752
250.86  (b)(2) amended.............................................47752
250.87  (d) amended................................................47753
250.107  (d) amended...............................................47753
250.123  (b)(1)(iii) and (7) introductory text amended.............47753
250.124  (a)(1)(ii) amended........................................47753
250.126  (c)(1) and (2) revised; (c)(3), (d), (e), and (f) added 
                                                                   10617
    (c)(2), (e)(1) and (3) revised.................................37710
    (e)(2) amended.................................................47753
250.142  (a) revised...............................................51415
250.159  (c)(7)(i) amended.........................................47753
256.7  (d) amended; (e) removed; (f) through (i) redesignated as 
        (e) through (h)............................................32908
256.70  Amended....................................................32908
265  Removed.......................................................32908
266  Removed.......................................................32908
267  Removed.......................................................32908
268  Removed.......................................................32908
Chapter VI
652.12  Amended....................................................35300
652.18  Correctly designated.......................................35301

[[Page 628]]

                                  1991

30 CFR
                                                                   56 FR
                                                                    Page
Chapter II
202  Authority citation revised....................................57275
    Training seminars..............................................66358
202.350--202.353 (Subpart H)  Added................................57275
203  Training seminars.............................................66358
206  Training seminars.............................................66358
206.152  (a)(1) and (b)(1)(i) revised..............................46530
206.153  (a)(1) revised............................................46530
206.350  Revised...................................................57276
206.351  Revised...................................................57276
206.352  Added.....................................................57278
206.353  Added.....................................................57279
206.354  Added.....................................................57280
206.355  Added.....................................................57281
206.356  Added.....................................................57283
206.357  Added.....................................................57284
206.358  Added.....................................................57285
210  Authority citation revised....................................57286
210.350  Revised...................................................57286
210.351  Revised...................................................57286
210.352  Revised...................................................57286
210.353  Added.....................................................57286
210.354  Added.....................................................57286
210.355  Added.....................................................57286
212  Authority citation revised....................................57286
212.50--212.52 (Subpart B)  Heading revised; authority citation 
        removed....................................................57286
212.350  Added.....................................................57286
212.351  Added.....................................................57286
216  Authority citation revised....................................20127
216.16  Added......................................................20127
220  Training seminar..............................................26032
228.100  (c) added.................................................10512
228.103  Existing text designated as (a) and revised; (b) added....10512
228.105  (a) revised; (c) added....................................10512
228.107  (a) revised...............................................10512
243.3  Heading added................................................5949
243.4  Added........................................................5949
    (b)(1) and (8) corrected........................................9251
250  Evaluation of MMS operating regulations.......................31870
250.0  Introductory text added; (d) through (f) revised.............1914
    (x) added.......................................................2685
    (n) revised....................................................21954
    (y) added......................................................32098
250.1  (c)(1), (2), (3), (d)(3), (9), (11), (12), (13) and (15) 
        revised....................................................32098
250.2  Amended.....................................................32098
250.10  (a)(3) revised; (d) redesignated as (d)(1); (d)(2) added 
                                                                   32099
250.14  (f) added..................................................32099
250.25  Added......................................................20129
250.32  (a) revised................................................32099
250.34  (b)(5) and (8)(i)(B) revised; (b)(9) through (15) 
        redesignated as (b)(11) through (17); new (b)(9) and (10) 
        added......................................................32099
250.40  (a) introductory text revised..............................32099
250.42  Introductory text amended..................................32100
250.43  (a) amended................................................32100
250.44  Amended....................................................32100
250.50--250.67 (Subpart D)  Heading revised........................32100
250.57  (g) revised; (h) added......................................1914
250.70--250.87 (Subpart E)  Heading revised........................32100
250.86  (d) revised; (e) added......................................1915
250.90--250.108 (Subpart F)  Heading revised.......................32100
250.106  (d) revised; (e) added.....................................1915
250.120--250.127 (Subpart H)  Heading revised......................32100
250.154  (b)(1) redesignated as (b)(1)(i); (b)(1)(ii) added........32100
250.170--250.177 (Subpart K)  Heading revised......................32100
250.180--250.183 (Subpart L)  Heading revised......................32100
250.190  (c) revised...............................................32100
250.194  (c) added.................................................32100
250.200  (a)(1) and (b) revised; (c) redesignated as (d); new (c) 
        added......................................................21954
250.203  (a) revised; (b) redesignated as (c); new (b) added.......21955
250.206  Heading and (a)(1) revised................................21955
250.210--250.215 (Subpart O)  Revised...............................2685
250.214  (c)(3) corrected..........................................12423
250.250--250.297 (Subpart P)  Revised..............................32100
260.110  (b) amended...............................................23648

                                  1992

30 CFR
                                                                   57 FR
                                                                    Page
Chapter II
202  Training seminars.............................................13320
206  Training seminars.............................................13320
206.10  Revised....................................................41863
206.254  (b) amended...............................................52720
206.257  (d)(3) amended............................................52720

[[Page 629]]

206.259  (c)(1)(i), (2)(i), (c)(4), (d)(1), (e)(1) and (2) amended
                                                                   52720
206.262  (a)(1) amended............................................41864
    (c)(1)(i), (2)(i), (4), (d)(1), (e)(1) and (2) amended.........52720
206.355  (c)(1)(ii) and (d)(1)(ii) corrected.......................12376
207  Training seminars.............................................13320
    Authority citation revised.....................................41864
207.1  Revised.....................................................41864
208  Authority citation revised....................................41864
208.3  Revised.....................................................41864
210  Authority citation revised....................................41864
210.10  Revised (OMB numbers)......................................41864
210.53  (a) revised................................................41867
210.202  Amended...................................................52720
210.204  (a) revised...............................................41867
216  Authority citation revised....................................41867
216.10  Revised....................................................41867
216.15  (a) revised................................................41867
216.16  (a) revised................................................41867
218.10  Added......................................................41867
218.40  (c) amended................................................52720
218.42  Added......................................................62206
218.51  (f)(1) revised.............................................41868
218.54  (e) added..................................................62206
218.102  (b) revised...............................................41868
    (d) added......................................................62206
218.150  (c) revised...............................................41868
    (e) added......................................................62206
218.155  (d)(3) and (4) revised....................................41868
218.202  (b) revised...............................................41868
    (f) added......................................................62207
218.302  (b) revised...............................................41868
    (f) added......................................................62207
219  Authority citation revised....................................41868
219.102  Revised...................................................41868
220.003  Added.....................................................41868
228  Authority citation revised....................................41868
228.10  Revised....................................................41868
230  Heading revised; text added...................................62207
243  Authority citation revised....................................44997
243.2  Revised.....................................................44997
243.3  Added.......................................................44998
250.153  (c)(4) redesignated as (b)(4).............................26997
Chapter IV
400  Removed.......................................................59916
Chapter VI
609  Removed.......................................................61831
651  Removed.......................................................61832

                                  1993

30 CFR
                                                                   58 FR
                                                                    Page
Chapter II
202  Policy statement..............................................37420
206  Policy statement..............................................37420
207  Authority citation revised....................................64901
207.1  (b) amended.................................................64901
208  Authority citation revised....................................64901
208.2  Amended.....................................................64901
208.3  Revised.....................................................64901
208.6  (a) revised.................................................64901
208.7  (h) amended.................................................64901
208.11  Revised....................................................64901
208.12  (a) amended; (c) and (d) revised...........................64902
208.13  Revised....................................................64902
210  Authority citation revised....................................64902
210.10  (a) table, (b)(3) through (6), (c)(1), (2), (8), (9), 
        (12), (13), (19) and (d) amended; (b)(1) revised; (c)(6), 
        (11), (15) and (17) removed; (c)(7) through (10), (12), 
        (13), (14), (16) and (18) through (23) redesignated as 
        (c)(6) through (19); new (c)(20) added; OMB number.........64902
210.53  (a) and (b) amended........................................64902
210.204  (a) and (b) amended.......................................64902
210.355  (a) and (b) amended.......................................64902
216  Authority citation revised.............................45254, 64903
216.2  Revised.....................................................45254
216.6  Amended.....................................................45254
216.15  (a) and (b) amended........................................64903
216.16  (a) and (b) amended........................................64903
216.20  Revised....................................................45254
216.40  (c) amended................................................64903
216.50  (a) removed; (b) through (e) redesignated as (a) through 
        (d); new (a) revised; new (d)(3) amended...................45254
    (a), (c)(1) and (2) amended....................................64903
216.51  Revised....................................................45254
216.52  Removed; new 216.52 redesignated from 216.53...............64903
216.53  Redesignated as 216.52; new 216.53 redesignated from 
        216.54.....................................................64903
216.54  Revised....................................................45255
    Redesignated as 216.53; new 216.54 redesignated from 216.55....64903
216.55  Revised....................................................45255
    Redesignated as 216.54; new 216.55 redesignated from 216.56....64903
216.56  Revised....................................................45255

[[Page 630]]

    Redesignated as 216.55; new 216.56 redesignated from 216.58....64903
216.57  Removed; new 216.57 added..................................64903
216.58  Revised....................................................45255
    Redesignated as 216.56.........................................64903
216.61  Removed....................................................64903
218  Authority citation revised.............................45438, 64903
218.41  Added......................................................45438
218.51  (a)(1) corrected; CFR correction............................8907
    (f)(2) amended.................................................64903
219.102  Amended...................................................64903
220.003  (b) amended...............................................64903
228.10  (b) amended................................................64903
229  Authority citation revised....................................64903
229.123  (b)(2) and (3)(vii) amended...............................64903
243.4  (b)(2) removed; (b)(3) through (9) redesignated as (b)(2) 
        through (8); new (b)(5) revised; new (b)(8) amended........64903
250.0  (r), (t) and (v) removed; (s), (u), (w), (x) and (y) 
        redesignated as (r) through (v); (o), (p), (q) and new (r) 
        through (u) revised........................................49926
250.18  (d) introductory text revised; (d)(4) through (8) added....44764
    (d)(1), (2) and (3) revised; (d)(4) and (5) added..............49927
250.51  (a)(3) amended.............................................49927
250.64  (a) and (f) introductory text revised......................49927
250.65  (a), (b) and (c) amended...................................49928
250.66  (b) and (e) amended........................................49928
250.83  (a) and (b) introductory text amended; (c) revised; (d) 
        added......................................................49928
250.85  (a) amended................................................49928
250.103  (a), (b) introductory text and (c) introductory text 
        amended; (d) revised.......................................49928
250.105  (a) amended...............................................49928
250.111  Introductory text amended.................................49928
250.114  (b) amended...............................................49928
250.121  (h)(1) amended............................................49928
250.172  (a)(1), (b)(2), (3), (5) and (6) revised; (a)(2), (3), 
        (6), (7) and (8) amended; (a)(9), (b)(8) and (9) added.....49928
250.260  (b)(3) amended............................................49928
250.272  (a) and (c) introductory text amended.....................49928
250.273  (a), (b) and (c) amended..................................49928
250.274  (b) amended...............................................49928
250.282  (a), (b) introductory text, (c)(1) and (2) amended........49928
254  Added; interim; eff. to 2-18-95................................7490
256  Heading revised...............................................45261
    Authority citation revised.....................................45261
256.0--256.12 (Subpart A)  Heading revised.........................45261
256.0  Revised.....................................................45261
256.58  Heading, (a), (c) and (e) revised; (f) redesignated as 
        (h); new (f) and (g) added.................................45261
256.59  Revised....................................................45262
256.61  Revised....................................................45262
256.62  (e) revised................................................45262
Chapter IV
401  Authority citation revised....................................27204
401.3  Amended.....................................................27204
401.4  Revised.....................................................27204
401.6  (c)(2) revised..............................................27204
401.11  (a) and (g) revised........................................27204
401.12  (c) revised................................................27204
401.26  Revised....................................................27204

                                  1994

30 CFR
                                                                   59 FR
                                                                    Page
Chapter II
206  Extraordinary cost provisions.................................17479
216  Authority citation revised....................................38905
216.40  (b) revised................................................38905
218  Authority citation revised.............................14559, 38906
218.40  (b) revised................................................38906
218.202  (c) and (d) revised.......................................14559
218.302  (c) and (d) revised.......................................14559
230  Authority citation revised....................................38363
230.451--230.461 (Subpart J)  Added................................38363
250  Authority citation revised....................................53093
250.2  Amended.....................................................53093
250.18  (d) revised................................................12161
250.26  Added......................................................53093
250.33  (b)(15) and (o) revised....................................53093
250.34  (b)(8)(v)(A) and (s) revised...............................53093
250.157  (a)(5) revised............................................53094
250.159  (c)(4) revised............................................53094
250.211  Amended...................................................64850
250.212  (a)(2) amended............................................64850

[[Page 631]]

250.213  Amended...................................................64850
250.214  Amended...................................................64850
256  Authority citation revised....................................53094
256.23  (b) amended................................................53094
280  Authority citation revised....................................53094
280.2  Amended.....................................................53094
281  Authority citation revised....................................53094
281.12  (c) amended................................................53094

                                  1995

30 CFR
                                                                   60 FR
                                                                    Page
Chapter II
Guidance availability..............................................36711
218.53  Added.......................................................3087
218.203  Added......................................................3087
250  Interpretation.................................................9298
254  Regulation at 58 FR 7490 eff. date extended....................9626

                                  1996

30 CFR
                                                                   61 FR
                                                                    Page
Chapter II
202  Authority citation revised.....................................5490
202.151  (a) revised................................................5490
203  Comment period extension......................................48834
203.1 (Subpart A)  Added; interim..................................27274
    (Subpart A)  Comment period extension..........................40734
203.50--203.56 (Subpart B)  Revised; interim.......................27274
206  Authority citation revised...............................3804, 5455
206.50--206.55 (Subpart B)  Added...................................5455
    (Subpart B)  Comment period extension..........................40734
206.100--206.105 (Subpart C)  Heading revised.......................5462
206.100  (a), (b) and (c) revised...................................5462
206.101  Amended....................................................5462
206.102  (a)(2) removed; (a)(1) redesignated as (a); (d), (i), (k) 
        and (l) revised.............................................5462
206.104  (b)(2) and (d) revised.....................................5462
206.105  (c)(1)(ii), (iii), (v), (vi), (2)(ii), (iii), (v), (vii), 
        (3) and (4) removed; (c)(1)(iv), (2)(iv), (vi) and (viii) 
        redesignated as (c)(1)(ii), (2)(ii), (iii) and (iv); 
        (a)(1)(i), (3), (b)(1), (2)(v), (4), (c)(1)(i), (2)(i), 
        new (ii), new (iii), (d) and (e) revised....................5463
206.106  Added......................................................3804
206.150--206.159 (Subpart D)  Heading revised.......................5464
206.150  Revised....................................................5464
206.151  Amended....................................................5464
206.152  (a)(2), (e)(2), (h), (i), (k) and (l) revised; (a)(3) 
        removed.....................................................5464
206.153  (a)(3) removed; (e)(2), (i), (k) and (l) revised...........5465
206.154  (c)(4) revised.............................................5465
206.155  (b) revised................................................5465
206.156  (c)(3) and (d) revised.....................................5465
206.157  (c)(1)(ii), (iii), (v), (vi), (2)(ii), (iii), (v), (vii), 
        (3) and (4) removed; (c)(1)(iv), (2)(iv), (vi) and (viii) 
        redesignated as (c)(1)(ii), (2)(ii), (iii) and (iv); 
        (a)(1)(i), (3), (b)(1), (2)(v), (4), (c)(1)(i), (2)(i), 
        new (ii), new (iii), (d), (e)(1) and (2) revised............5465
206.158  (c)(3) and (e) revised.....................................5466
206.159  (c)(1)(ii), (iii), (v), (vi), (2)(ii), (iii), (v), (vii), 
        (3) and (4) removed; (c)(1)(iv), (2)(iv), (vi) and (viii) 
        redesignated as (c)(1)(ii), (2)(ii), (iii) and (iv); 
        (a)(1)(i), (3), (b)(1), (2)(v), (c)(1)(i), (2)(i), new 
        (ii), new (iii), (d), (e)(1) and (2) revised................5466
206.160  Added......................................................3804
206.170--206.179 (Subpart E)  Added.................................5467
206.250--206.265 (Subpart F)  Heading revised.......................5479
206.250  (d) removed; (a) and (b) revised...........................5479
206.251  Amended....................................................5479
206.253  (a) and (c) revised........................................5479
206.255  (a) and (b) revised........................................5480
206.256  (a) revised................................................5480
206.257  (a), (d)(2), (h), (j) and (k) revised......................5480
206.258  (c) revised................................................5480
206.259  (c)(1)(ii), (iii), (v), (vi), (2)(ii), (iii), (v), (vii), 
        (3) and (4) removed; (c)(1)(iv), (2)(iv) and (vi) 
        redesignated as (c)(1)(ii), (2)(ii) and (iii); (a)(1), 
        (b)(1), (2)(v), (c)(1)(i), (2)(i), new (ii), new (iii), 
        (d) and (e)(1) revised......................................5480
206.261  (a)(1), (2) and (e) revised................................5481

[[Page 632]]

206.262  (c)(1)(ii), (iii), (v), (vi), (2)(ii), (iii), (v), (vii), 
        (3) and (4) removed; (c)(1)(iv), (2)(iv), (vi) and (viii) 
        redesignated as (c)(1)(ii), (2)(ii), (iii) and (v); 
        (a)(1), (b)(1), (2)(v), (b)(3), (c)(1)(i), (2)(i), new 
        (ii), new (iii), (d) and (e) revised........................5481
206.450--206.464 (Subpart J)  Added.................................5481
250.1  Introductory text amended; (a)(1), (b), (c)(1) through (4), 
        (6), (d), (e)(1) through (5), (f)(1) and (g)(2) revised....60022
250.13  Revised....................................................55887
250.53  (b) revised................................................60024
250.122  (e)(4)(i) introductory text revised.......................60024
250.123  (b)(9)(i) revised.........................................60025
250.126  (c)(3), (e)(2) and (3) revised............................60025
250.137  (b)(1)(ii), (c)(4)(ii) and (vii) revised..................60025
250.138  (b)(4)(i), (6)(i), (7), (8)(i), (9), (10), (c)(3), 
        (d)(1)(v), (5) through (9), (e)(1)(i) and (2)(i) revised 
                                                                   60025
250.175  Revised...................................................25148
250.180  (c)(6)(i), (ii), (v), (vi), (viii)(A), (C), (d)(3)(iv), 
        (v)(B), (f)(2)(i), (ii), (iv), (v) and (vii) revised.......60026
250.181  (c)(1) revised............................................60026
250.291  (b)(3) and (d)(4)(i) revised..............................60026
250.292  (b)(4)(i) revised.........................................60026
256.37  (a) concluding text removed; (a)(2) revised; (a)(3) added 
                                                                   55889
256.47  (e)(2) revised.............................................34732
260  Authority citation revised.....................................3804
260.001  Revised....................................................3804
260.002  Amended....................................................3804
260.102  Amended; interim..........................................12027
260.110  (a)(1)(iii), (2)(iii), (3)(i)(C)(4) and (iii) revised; 
        (a)(5), (6) and (7) added...................................3804
    (d) added; interim.............................................12027

                                  1997

30 CFR
                                                                   62 FR
                                                                    Page
Chapter II
206.152  (b)(1)(i) amended; (b)(1)(iv) added.......................65761
    (i) revised....................................................65762
206.153  (b)(1)(i) amended; (b)(1)(iv) added; (i) revised..........65762
206.157  (f) removed; (g) redesignated as (h); new (f) and new (g) 
        added......................................................65762
206.172  (b)(1)(i) amended; (b)(1)(iv) added; (i) revised..........65763
206.173  (b)(1)(i) amended; (b)(1)(iv) added; (i) revised..........65763
206.177  (f) removed; (g) redesignated as (h); new (f) and new (g) 
        added......................................................65763
210  Comment period extension......................................52016
210.55  Revised; interim...........................................42066
218  Authority citation revised....................................19498
    Comment period extension.......................................52016
218.51  Revised....................................................19498
218.52  Revised; interim...........................................42066
218.155  (b)(1) amended............................................19499
227  Added.........................................................43084
228  Authority citation revised....................................43091
228.3  Added.......................................................43091
229  Authority citation revised....................................43091
229.3  Added.......................................................43091
250  Authority citation revised....................................27954
250.1  (c)(7) and (g)(1) revised....................................3795
      (c)(4) designation corrected, (d)(61) corrected..............33156
    (c)(5) and (d)(1) revised......................................42671
250.2  Amended......................................................3795
250.8  Revised; eff. 8-20-97.......................................27954
250.13  (b)(2) corrected...........................................35247
250.19  (a) amended................................................13996
250.33  (b)(2) revised.............................................13996
250.34  (b)(3) revised.............................................13996
250.41  Heading revised; (b) and (c) removed.......................13996
250.42  Removed....................................................13996
250.43  Removed....................................................13996
250.67  Revised.....................................................3795
250.110  Existing text designated as (a); (b) added; eff. 8-20-97 
                                                                   27955
250.124  (a)(3)(i) revised..........................................5331
250.126  Revised...................................................42671
250.159  (b)(1) revised; eff. 8-20-97..............................27955
250.160  (a) amended...............................................39775
250.163  (b) amended...............................................39775
250.175  Heading revised; (f) added.................................3800
250.190--250.194 (Subpart M)  Revised...............................5331
250.200--250.209 (Subpart N)  Revised..............................42668
250.209--250.232 (Subpart O)  Revised...............................5322

[[Page 633]]

250.209--250.233 (Subpart O)  Redesignated as250.210--250.234 
        (Subpart O)................................................67284
250.209  (c) revised...............................................67284
250.214  Corrected..................................................7298
250.228  (a)(4)(i) and (iii) corrected..............................7298
250.229  Corrected..................................................7298
251  Authority citation revised....................................27955
    Revised........................................................67284
251.6-4  Revised; eff. 8-20-97.....................................27955
254  Revised.......................................................13996
254.9  (d) correctly revised.......................................18041
256.7  (b) through (h) redesignated as (c) through (i); new (b) 
        added; eff. 8-20-97........................................27955
256.47  (f) amended; eff. 8-20-97..................................27955
256.52  Redesignated from 256.58 and revised; eff. 8-20-97.........27955
256.53  Redesignated from 256.61; (a) introductory text, (b) 
        introductory text, (e), and (f) added; (a)(1), (b)(1) and 
        (d) revised; eff. 8-20-97..................................27956
256.53  Corrected..................................................36995
256.54  Redesignated from 256.59 and revised; eff. 8-20-97.........27956
256.55  Added; eff. 8-20-97........................................27957
256.56  Added; eff. 8-20-97........................................27957
256.57  Added; eff. 8-20-97........................................27957
256.58  Redesignated as 256.52; eff. 8-20-97.......................27955
    Added; eff. 8-20-97............................................27958
256.59  Redesignated as 256.54; eff. 8-20-97.......................27956
    Added; eff. 8-20-97............................................27958
256.61  Redesignated as 256.53; eff. 8-20-97.......................27956
256.62  Heading, (a), (d) and (e) revised; introductory text and 
        (f) added; eff. 8-20-97....................................27959
256.64  Introductory text and (a) introductory text amended; 
        (a)(2) and (d) through (h) redesignated as (8) and (e) 
        through (i); eff. 8-20-97..................................27959
    (a)(8) amended.................................................39775
281  Authority citation revised....................................27960
281.33  (b) introductory text amended; eff. 8-20-97................27960
282  Authority citation revised....................................27960
282.40  (b) amended; eff. 8-20-97..................................27960

                                  1998

30 CFR
                                                                   63 FR
                                                                    Page
Chapter II
202.152  (a)(1) revised............................................26367
    Regulation at 63 FR 26367 eff. date corrected to 6-29-98.......27677
    Regulation at 63 FR 27677 eff. date corrected to 6-29-98.......28453
203  Workshop......................................................17330
203.0--203.4 (Subpart A)  Revised...................................2615
    Heading correctly revised......................................24747
203.50--203.91 (Subpart B)  Revised.................................2618
    Heading amended................................................57249
    (a) amended....................................................57249
203.61  OMB number pending..........................................2619
203.74  (b)(2) and (c) corrected...................................24747
203.84  (b) introductory text amended; (b)(7) and (c) revised......57249
206.152  Corrected..................................................3618
206.173  (b)(1)(i) corrected........................................3618
216.54  Revised....................................................26367
    Regulation at 63 FR 26367 eff. date corrected to 6-29-98.......27677
    Regulation at 63 FR 27677 eff. date corrected to 6-29-98.......28453
250.0--250.26 (Subpart A)  Redesignated as 250.100--250.126 
        (Subpart A)................................................29479
250.1  Revised.....................................................26367
    Regulation at 63 FR 26367 eff. date corrected to 6-29-98; (a) 
corrected..........................................................27677
    Regulation at 63 FR 27677 eff. date corrected to 6-29-98.......28453
250.30--250.34 (Subpart B)  Redesignated as 250.200--250.204 
        (Subpart B)................................................29479
250.40  Redesignated as 250.300....................................29479
250.41  Redesignated as 250.301....................................29479
250.44  Redesignated as 250.302....................................29479
250.45  Redesignated as 250.303....................................29479
250.46  Redesignated as 250.304....................................29479
250.50--250.67 (Subpart D)  Redesignated as 250.400--250.417 
        (Subpart D)................................................29479
250.70--250.87 (Subpart E)  Redesignated as 250.500--250.517 
        (Subpart E)................................................29479
250.90--250.108 (Subpart F)  Redesignated as 250.600--250.618 
        (Subpart F)................................................29479
250.100--250.126 (Subpart A)  Redesignated from 250.0--250.26 
        (Subpart A)................................................29479

[[Page 634]]

250.101  (e) table revised.........................................29481
    (c) amended....................................................29484
    (e) Table 1 amended............................................37068
250.102  Amended...................................................29484
250.110--250.114 (Subpart G)  Redesignated as 250.700--250.704 
        (Subpart G)................................................29479
250.110  (c), (d)(1), (2) and (h)(2) amended.......................29484
250.112  (c)(1) and (e)(2) amended.................................29484
250.113  (b)(2) and (3) amended....................................29484
250.114  (e) amended...............................................29484
250.117  (b) amended...............................................29484
250.118  (b)(2) amended............................................29484
    (b)(2) and (e) amended.........................................29485
250.120--250.127 (Subpart H)  Redesignated as 250.800--250.807 
        (Subpart H)................................................29479
250.130--250.144 (Subpart I)  Redesignated as 250.900--250.914 
        (Subpart I)................................................29479
250.150--250.164 (Subpart J)  Redesignated as 250.1000--250.1014 
        (Subpart J)................................................29479
250.170--250.177 (Subpart K)  Redesignated as 250.1100--250.1107 
        (Subpart K)................................................29479
250.180--250.185 (Subpart L)  Revised..............................26370
    Regulation at 63 FR 26370 eff. date corrected to 6-29-98.......27677
    Regulation at 63 FR 27677 eff. date corrected to 6-29-98.......28453
    Redesignated as 250.1200--250.1205 (Subpart L).................29479
250.182  (g) corrected.............................................27677
    (g) and (k) corrected..........................................33853
250.183  (b)(1) correctly revised..................................33853
250.184  (a)(1) correctly revised; (b)(7) corrected................33853
250.190--250.194 (Subpart M)  Redesignated as 250.1300--250.1304 
        (Subpart M)................................................29479
250.200--250.209 (Subpart N)  Redesignated as 250.1400--250.1409 
        (Subpart N)................................................29479
250.200--250.204 (Subpart B)  Redesignated from 250.30--250.34 
        (Subpart B)................................................29479
250.200  Amended...................................................29485
250.203  (b)(5)(i), (ii), (19), (m) and (p) amended................29485
250.204  (b)(1)(vii), (2)(i), (ii), (14), (p), (r) and (t) amended
                                                                   29485
250.210--250.234 (Subpart O)  Redesignated as 250.1500--250.1524 
        (Subpart O)................................................29479
250.250  Redesignated as 250.1600..................................29479
250.251  Redesignated as 250.1601..................................29479
250.252  Redesignated as 250.1602..................................29479
250.253  Redesignated as 250.1603..................................29479
250.254  Redesignated as 250.1604..................................29479
250.260  Redesignated as 250.1605..................................29479
250.261  Redesignated as 250.1606..................................29479
250.262  Redesignated as 250.1607..................................29479
250.263  Redesignated as 250.1608..................................29479
250.264  Redesignated as 250.1609..................................29479
250.265  Redesignated as 250.1610..................................29479
250.266  Redesignated as 250.1611..................................29479
250.267  Redesignated as 250.1612..................................29479
250.268  Redesignated as 250.1613..................................29479
250.269  Redesignated as 250.1614..................................29479
250.270  Redesignated as 250.1615..................................29479
250.271  Redesignated as 250.1616..................................29479
250.272  Redesignated as 250.1617..................................29479
250.273  Redesignated as 250.1618..................................29479
250.274  Redesignated as 250.1619..................................29479
250.280  Redesignated as 250.1620..................................29479
250.281  Redesignated as 250.1621..................................29479
250.282  Redesignated as 250.1622..................................29479
250.283  Redesignated as 250.1623..................................29479
250.284  Redesignated as 250.1624..................................29479
250.285  Redesignated as 250.1625..................................29479

[[Page 635]]

250.286  Redesignated as 250.1626..................................29479
250.290  Redesignated as 250.1627..................................29479
250.291  Redesignated as 250.1628..................................29479
250.292  Redesignated as 250.1629..................................29479
250.293  Redesignated as 250.1630..................................29479
250.294  Redesignated as 250.1631..................................29479
250.295  Redesignated as 250.1632..................................29479
250.296  Redesignated as 250.1633..................................29479
250.297  Redesignated as 250.1634..................................29479
250.300  Redesignated from 250.40..................................29479
250.301  Redesignated from 250.41..................................29479
250.302  Redesignated from 250.44..................................29479
250.302  Amended...................................................29485
250.303  Redesignated from 250.45..................................29479
250.303  (b) and (d) amended.......................................29485
250.304  Redesignated from 250.46..................................29479
250.304  (a)(6), (b) and (e)(2) amended............................29485
250.400--250.417 (Subpart D)  Redesignated from 250.50--250.67 
        (Subpart D)................................................29479
250.401  (a)(3) and (d) amended....................................29485
250.406  (c) and (d)(10)(i) amended................................29485
    (d)(10)(i) revised.............................................29607
250.407  Revised...................................................29607
250.414  (a) and (g) amended.......................................29485
250.415  (d) amended...............................................29485
250.416  (b) amended...............................................29485
250.417  (m)(1) and (o)(3) amended.................................29485
250.500--250.517 (Subpart E)  Redesignated from 250.70--250.87 
        (Subpart E)................................................29479
250.504  Amended...................................................29485
250.505  Amended...................................................29485
250.507  Amended...................................................29485
250.508  Amended...................................................29485
250.513  (a), (b)(4) and (d) amended...............................29485
250.516  Revised...................................................29607
250.517  (e) amended...............................................29485
250.600--250.618 (Subpart F)  Redesignated from 250.90--250.108 
        (Subpart F)................................................29479
250.604  Amended...................................................29485
250.605  Amended...................................................29485
250.607  Amended...................................................29485
250.608  Amended...................................................29485
250.613  (b)(3) amended............................................29485
250.617  (e) amended...............................................29485
250.618  Amended...................................................29485
250.700--250.704 (Subpart G)  Redesignated from 250.110--250.114 
        (Subpart G)................................................29479
250.702  (i) amended...............................................29485
250.703  (a) amended...............................................29485
250.800--250.807 (Subpart H)  Redesignated from 250.120--250.127 
        (Subpart H)................................................29479
250.801  (b), (h)(1), (2) and (4) amended..........................29485
250.802  (b) and (c) amended.......................................29485
250.803  (a), (b)(10) and (d) amended..............................29485
250.806  (a)(3) revised............................................37068
250.807  Amended...................................................29485
250.900--250.914 (Subpart I)  Redesignated from 250.130--250.144 
        (Subpart I)................................................29479
250.900  (b) and (c) amended.......................................29485
250.901  (b)(1)(v)(D) and (2) amended..............................29485
    (b)(3)(v), (4)(vi)(A) and (B) amended..........................29486
250.902  (a), (b)(1)(i) and (2)(i) amended.........................29486
250.903  (a)(1)(iii), (2)(ii), (3)(i), (ii), and (b)(2) amended....29486
250.904  (d)(4)(ii) and (8)(ii) amended............................29486
250.905  (c)(2)(vii) and (5)(ii) amended...........................29486
250.906  (b)(2)(ii), (iii), (3)(i), (ii), (c)(1) and (5) amended 
                                                                   29486
    (b)(2)(iii) corrected..........................................34597
250.907  (c)(1)(iii), (3)(iv), (4)(v) and (6)(ii) amended..........29486
250.908  (b)(6)(ii), (c)(5)(ii) and (6) amended....................29486
250.911  (b)(4), (7)(iii)(D), (iv), (3)(ii) and (8)(iv) amended....29486
250.914  Amended...................................................29486
250.1000--250.1014 (Subpart J)  Redesignated from 250.150--250.164 
        (Subpart J)................................................29479
250.1000  (b), (c) and (d) amended.................................29486

[[Page 636]]

    (c) corrected..................................................34597
    (c) revised....................................................43880
250.1001  Amended..................................................43881
250.1007  Heading and (a) introductory text revised; (a)(2) 
        amended....................................................43881
250.1008  (h) amended..............................................29486
250.1009  (a)(1) and (c)(9) amended................................29486
    (a)(1) corrected...............................................34597
250.1010  (a) amended..............................................29486
250.1011  (c)(1) amended...........................................29486
250.1013  (b) amended..............................................29486
250.1014  Amended..................................................29486
250.1100--250.1107 (Subpart K)  Redesignated from 250.170--250.177 
        (Subpart K)................................................29479
250.1101  (d) amended..............................................29486
250.1102  (a)(9), (b)(8) and (9) amended...........................29486
250.1105  (f)(1)(i) and (ii) amended...............................29486
250.1200--250.1205 (Subpart L)  Redesignated from 250.180--250.185 
        (Subpart L)................................................29479
250.1200  Table revised............................................29487
250.1201  Amended..................................................29486
250.1202  (a)(3), (b)(4)(i), (f)(1), (g), (k)(1) and (l)(4) 
        amended....................................................29486
250.1203  (b)(2) and (4) amended...................................29486
250.1300--250.1304 (Subpart M)  Redesignated from 250.190--250.194 
        (Subpart M)................................................29479
250.1301  (d), (g)(1) and (2)(ii) amended..........................29486
250.1302  (d) amended..............................................29486
250.1303  (a)(4) amended...........................................29487
250.1304  (b) amended..............................................29487
250.1400--250.1409 (Subpart N)  Redesignated from 250.200--250.209 
        (Subpart N)................................................29479
250.1401  Table revised............................................29488
250.1404  (d) added................................................42711
250.1405  Amended..................................................29487
250.1500--250.1524 (Subpart O)  Redesignated from 250.210--250.234 
        (Subpart O)................................................29479
250.1500  (a) through (d) amended..................................29487
    Table revised..................................................29488
    (a) through (d) corrected......................................34597
250.1505  (c) and (f) amended......................................29487
    (c) and (f) corrected..........................................34597
250.1600  Redesignated from 250.250................................29479
250.1601  Redesignated from 250.251................................29479
250.1602  Redesignated from 250.252................................29479
250.1603  Redesignated from 250.253................................29479
250.1604  Redesignated from 250.254................................29479
    (b), (c) and (d) amended.......................................29487
250.1605  Redesignated from 250.260................................29479
    (a), (b)(3) and (d) amended....................................29487
    (a) corrected..................................................34597
250.1606  Redesignated from 250.261................................29479
250.1607  Redesignated from 250.262................................29479
250.1608  Redesignated from 250.263................................29479
250.1609  Redesignated from 250.264................................29479
250.1610  Redesignated from 250.265................................29479
250.1611  Redesignated from 250.266................................29479
250.1612  Redesignated from 250.267................................29479
    Amended........................................................29487
250.1613  Redesignated from 250.268................................29479
250.1614  Redesignated from 250.269................................29479
    (b) amended....................................................29487
250.1615  Redesignated from 250.270................................29479
250.1616  Redesignated from 250.271................................29479
250.1617  Redesignated from 250.272................................29479
    (a) and (d) amended............................................29487
250.1618  Redesignated from 250.273................................29479
    (a) and (c) amended............................................29487
250.1619  Redesignated from 250.274................................29479
    (b) amended....................................................29487
250.1620  Redesignated from 250.280................................29479
    (a) amended....................................................29487
250.1621  Redesignated from 250.281................................29479
250.1622  Redesignated from 250.282................................29479
250.1623  Redesignated from 250.283................................29479

[[Page 637]]

250.1624  Redesignated from 250.284................................29479
    (d)(1) amended.................................................29487
250.1625  Redesignated from 250.285................................29479
250.1626  Redesignated from 250.286................................29479
250.1627  Redesignated from 250.290................................29479
    (a) amended....................................................29487
    (a) corrected..................................................34597
250.1628  Redesignated from 250.291................................29479
250.1629  Redesignated from 250.292................................29479
250.1630  Redesignated from 250.293................................29479
250.1631  Redesignated from 250.294................................29479
250.1632  Redesignated from 250.295................................29479
250.1633  Redesignated from 250.296................................29479
250.1634  Redesignated from 250.297................................29479
253  Added (OMB numbers pending)...................................42711
    Workshop.......................................................43624
253.15  (f) corrected..............................................48578
260.102  Amended....................................................2629
260.110  (d) revised................................................2629
Chapter VI
602  Removed; interim..............................................40178
    Regulation at 63 FR 40178 confirmed............................66762

                                  1999

30 CFR
                                                                   64 FR
                                                                    Page
Chapter II
202  Training sessions.............................................56454
    Eligible index zones...........................................66771
202.51  (b) revised................................................43513
202.150--202.152(Subpart  D) Heading revised.......................43513
202.150  (b)(1), (e)(1), (2) and (f) amended.......................43513
202.151  (a)(2) amended............................................43513
202.550--202.558 (Subpart J)  Added................................43514
206  Training sessions.............................................56454
    Eligible index zones...........................................66771
206.51  Amended....................................................43288
206.53  (c) amended................................................43288
206.151  Amended...................................................43288
206.156  (d) amended...............................................43288
206.158  (e) amended...............................................43288
206.159  (a)(1)(i) and (e)(2) amended..............................43288
206.160  Correctly designated......................................43288
206.170--206.181 (Subpart E)  Revised..............................43515
206.172  (h) amended...............................................43288
206.173  (a)(2) amended............................................43288
206.174  (d)(2) amended............................................43288
206.176  (c)(3) amended............................................43288
206.177  (b)(3)(ii) and (d)(1) amended.............................43288
206.251  Amended...................................................43288
206.258  (a) amended...............................................43288
206.259  (c)(2)(ii) amended........................................43288
206.261  (b) revised...............................................43288
206.262  (c)(2)(v) redesignated as (c)(2)(iv); (d)(2) and (3) 
        added; (e)(2) revised......................................43288
206.263  (b) amended...............................................43289
206.264  Amended...................................................43289
206.451  Amended...................................................43289
206.457  (a) amended...............................................43289
206.460  (b) revised...............................................43289
206.461  (e)(1) amended............................................43289
206.462  (b) and (c) amended.......................................43289
206.463  Amended...................................................43289
206.464  (a) amended...............................................43289
208  Authority citation revised....................................26251
208.2  Amended.....................................................26251
208.16  Revised....................................................26251
210  Authority citation revised....................................38122
210.10  (c)(1), (2), (7) and (d) revised...........................38122
210.20--210.22 (Subpart A)  Added..................................38122
210.52  Revised....................................................38123
216  Authority citation revised....................................38123
216.11  Added......................................................38123
216.50  (a) revised; (b), (c) and (d) redesignated as (f), (g) and 
        (h); new (b) through (e) added.............................38123
216.53  Revised....................................................38123
216.55  Revised....................................................38123
216.56  (b) revised; (c) added.....................................38123
218.154  (a) and (b) revised.......................................72775
227.101  Revised...................................................36784
241.20  Removed....................................................26251
241.50--241.80 (Subpart B)  Revised................................26251
242  Heading revised...............................................26254
243  Revised.......................................................26254
250.101--250.199 (Subpart A)  Revised..............................72775
250.101  (e) table amended.........................................69923

[[Page 638]]

250.203  (f) revised...............................................53200
    (m) amended....................................................72794
250.204  (b)(1)(vii) amended........................................9065
    (i) and (j) revised............................................53200
    (p) and (r) amended............................................72794
250.304  (e)(2) amended............................................72794
250.402  Removed...................................................72794
250.403  Removed...................................................72794
250.413  (c) amended................................................9065
250.414  (a) and (g) amended.......................................72794
250.415  (d) amended...............................................72794
250.416  (b) amended...............................................72794
250.507  Removed...................................................72794
250.508  Removed...................................................72794
250.513  (d) amended...............................................72794
250.604  Amended....................................................9065
250.607  Removed...................................................72794
250.608  Removed...................................................72794
250.900  (b) amended................................................9065
250.901  (b)(3)(iv) amended.........................................9065
250.911  (b)(4)(ii) amended.........................................9065
250.1009  (b)(2) revised............................................9065
250.1010  (a) amended..............................................42598
250.1102  (a)(9), (b)(8) and (9) amended...........................72794
250.1201  Introductory text amended................................72794
250.1202  (a)(3), (b)(4)(i), (g) introductory text, (k)(1) and 
        (l)(4) amended.............................................72794
250.1203  (b)(2) and (4) amended...................................72794
250.1301  (d), (g)(1) and (2)(ii) amended..........................72794
250.1403  Revised...................................................9065
250.1404  (b) revised...............................................9066
250.1406  (b) revised...............................................9066
250.1409  Revised..................................................26257
250.1507  Table amended............................................72794
250.1617  (a) and (d) amended......................................72794
250.1618  (a) amended..............................................72794
250.1619  (b) amended..............................................72794
250.1629  (a) amended..............................................72794
252.7  (a)(2)(i) and (ii) amended..................................72794
253.11  (b)(2) amended.............................................72794
253.51  (d) amended................................................72794
256  Authority citation revised....................................72795
256.1  Revised.....................................................72795
256.4  Revised.....................................................72795
256.35  (c) added..................................................72795
256.46  (b) revised................................................40767
256.52  (b) revised; (c) and (h)(2) amended.........................9066
256.56  (a)(1) amended..............................................9066
256.70  Amended..............................................9066, 72795
256.73  (a) and (b) amended.........................................9066
    Revised........................................................72795
256.76  (a)(3) amended..............................................9066
256.77  (d)(3) amended......................................13343, 72795
270.6  Amended......................................................9066
270.7  Amended......................................................9066
282.28  (a) amended..........................................9066, 72795
290  Revised.......................................................26257
290.110  Added.....................................................50753
290.111  Added.....................................................50753

                                  2000

   (Regulations published from January 1, 2000, through July 1, 2000)

30 CFR
                                                                   65 FR
                                                                    Page
Chapter II
202  Eligible index zones...........................................1542
    Training sessions..............................................11468
203.82  (d) revised.................................................2875
206  Eligible index zones...........................................1542
    Training sessions.......................................11468, 24387
    Publications approval..........................................37043
206.100--206.121 (Subpart C)  Revised..............................14088
250.114  (a) revised.................................................219
250.142  Correctly revised..........................................6536
250.198  (e) table amended...............................218, 219, 15863
    (e) table corrected............................................14470
    Corrected......................................................18432
    (e) table amended..............................................25285
    (e) table corrected...............................3127, 36328, 40052
250.410  (e) corrected.............................................40052
250.417  (p)(2) revised............................................15864
250.613  (a) amended...............................................35824
250.802  (e)(4)(i) introductory text revised.........................219
250.803  (b)(9)(i) amended...........................................219
250.804  (a)(4) amended............................................35824
250.908  (b)(2)(i), (4)(i) and (e)(2)(i) revised...................15864
250.1102  (b)(2) amended............................................2875
250.1409  (d)(3) amended............................................2875
250.1605  (g) revised..............................................15864
250.1628  (b)(3) and (d)(4)(i) revised...............................219

[[Page 639]]

250.1629  (b)(4)(i) amended..........................................219
251.10  (c) revised.................................................3856
251.15  (e) revised.................................................2875
253.5  (d) revised..................................................2876
254.8  Revised......................................................3857
254.9  (d) revised..................................................2876
256.0  Revised......................................................2876
282.50  Revised.....................................................3857